Gas diverter for well and reservoir stimulation

ABSTRACT

The disclosure provides fracturing methods having advantage over current fracturing methods. The disclosed fracturing methods can change the fracture gradient of the downhole subterranean formation. For example, one or more of the fracture gradients of the low and high stress zones of the downhole subterranean formation can be changed. Furthermore, in relation to current practices, the methods can decrease the extent and/or degree of fracturing within low stress downhole formations and increase the degree of fracturing within high stress formations.

CROSS REFERENCE TO RELATED APPLICATIONS

The present application is a continuation application of and claimspriority to U.S. patent application Ser. No. 14/957,182, which was filedDec. 2, 2015, which claims priority under 35 U.S.C. § 119 to U.S.Provisional Patent Application Nos. 62/196,485, which was filed Jul. 24,2015; 62/209,201, which was filed Aug. 24, 2015; 62/248,890, which wasfiled on Oct. 30, 2015; 62/248,907, which was filed Oct. 30, 2015;62/250,361, which was filed Nov. 3, 2015; 62/250,365, which was filedNov. 3, 2015; and 62/260,090, which was filed Nov. 25, 2015, and whichis a continuation-in-part of and claims priority to U.S. patentapplication Ser. No. 14/728,719 (now U.S. Pat. No. 9,759,053), which wasfiled Jun. 2, 2015, which is a continuation-in-part of and claimspriority to U.S. patent application Ser. No. 14/690,208 (now U.S. Pat.No. 9,828,843), which was filed Apr. 17, 2015, which claims priorityunder 35 U.S.C. § 119 to U.S. Provisional Patent Application No.62/145,439, which was filed Apr. 9, 2015, all of which are entitled “GASDIVERTER FOR WELL AND RESERVOIR STIMULATION,” and each of which isincorporated in its entirety herein by this reference.

BACKGROUND

Oil and gas wells are stimulated and re-stimulated in various ways toincrease production of a flow of hydrocarbons from a completed well.With a newly completed well with a large reservoir and easily capturedhydrocarbons, for example, the well may not require much or anystimulation techniques to produce an adequate flow of hydrocarbons fromthe well. Other wells, depending on composition or otherwise, mayrequire more well stimulation to release the hydrocarbons from thesubterranean formation containing the hydrocarbons.

In recent years, hydraulic fracturing has become a widely-used wellstimulation technique to increase well production and access previouslyuncaptured hydrocarbons. Hydraulic fracturing involves hydraulicallyfracturing the subterranean formation with a pressurized liquid orfracturing liquid, containing water, proppant (e.g., sand or man-madealternative), and/or chemicals, that is injected into a wellbore. Uponpressurizing the wellbore with the fracturing liquid, the formationfractures or cracks and the fracturing liquid can leave behind proppant,propping open the formation which allows the hydrocarbons to flow morefreely through the fractures and into the wellbore to be recovered. Insome instances, an artificial lift system may pump hydrocarbons from thereservoir to overcome the hydrostatic head pressure of the hydrocarbons,or the hydrocarbons may flow freely up the wellbore without assistance.

SUMMARY

These and other needs are addressed by the present disclosure. Aspectsof the present disclosure can have advantages over current practices. Incontrast to current practices, the process(es) of the present disclosurecan, in accordance with some embodiments, change the fracture gradientof a downhole formation. For example, the processes described herein canchange one or more of the fracture gradients of the low and high stressdownhole formations. More particularly, the process of the presentdisclosure in relation to the current practices can decrease the extentand/or degree of fracturing within the low stress downhole formationsand increase the degree of fracturing within the high stress formations.Furthermore, the processes of the present disclosure can be conducted inthe absence or substantial absence of solid particulates. It can beappreciated that solid particles can be detrimental to well health andproductivity. Moreover, the process of the present disclosure can beused in any well bore orientation, whether horizontal, vertical or inbetween. It can be appreciated that the advantages of processes of thepresent disclosure can improve well economics and increase recoverablereserves. While not wanting to be bound by any theory, it is believedthe processes described within this disclosure can change the fracturepressure gradient of a downhole formation by changing the stress profileand therefore easier to fracture with a fracturing liquid. It is furtherbelieved that injecting a gas and/or foam can increase the formationpore pressures of the high and low stress formations exposed by the wellbore. Moreover, it is believed that injecting of the gas and/or foam cansubstantially equalize the pore pressures of the high and low stressformations. It can be appreciated that one or both of the increased porepressures of the high and low stress formations and the substantiallyequalized pore pressures of the high and low stress formations canchange the fracture gradients of one or both of the high and low stressformations compared to current practices.

In accordance with some aspects of the present disclosure is a processand/or method of treating a subterranean formation penetrated by awellbore. The process and/or method can include introducing agas-containing composition comprising one or more of gases, a foam, or amixture of gas and foam into one or more features of the subterraneanformation extending from the wellbore. The one or more features cancomprise fractures, pore volumes or a combination of factures and porevolumes. The method and/or process can further include introducing adiverting composition into the one or more features of the subterraneanformation extending from the wellbore. Typically, the divertingcomposition is introduced into the subterranean formation after theintroduction of the gas-containing composition into the subterraneanformation. However, in some embodiments, the diverting composition canbe introduced into the subterranean formation before the introduction ofthe gas-containing composition. Generally, the diverting compositioncontains one or more of a diverting fluid and a diverting agent. Thediverting fluid can be a gas-phase fluid or a liquid-phase fluid.Commonly, the diverting fluid is a liquid-phase fluid. In accordancewith some embodiments, the process and/or method can include introducinga fracturing liquid into the subterranean formation. The fracturingliquid can be introduced into the subterranean formation undersufficient pressure. It can be appreciated that the introducing of thefracturing liquid into the subterranean formation under sufficientpressure can fracture a portion of the subterranean formation. It can befurther appreciated that the fracturing of a portion of the subterraneanformation can release hydrocarbons from the subterranean formation. Itis believed that the gas occupies the features at a sufficient pressureto cause the fracturing liquid to be diverted to additional features ofthe subterranean formation defined by the portion, the additionalfeatures including additional fractures or pore volumes.

Aspects of the present disclosure involve a method of treating asubterranean formation penetrated by a wellbore. The method includesintroducing a composition comprising a gas (or foam) into features ofthe subterranean formation extending from the wellbore, the featuresincluding fractures or pore volumes. The method further includesintroducing a diverting composition including a fluid and a divertingagent into the features of the subterranean formation extending from thewellbore. The method further includes introducing a fracturing liquidinto the subterranean formation under sufficient pressure to fracture aportion of the subterranean formation and release hydrocarbons from thesubterranean formation, wherein the gas occupies the features at asufficient pressure to cause the fracturing liquid to be diverted toadditional features of the subterranean formation defined by the portionand the additional features including additional fractures or porevolumes.

Aspects of the present disclosure may also involve a method of treatinga subterranean formation penetrated by a wellbore. The method mayinclude introducing a first diverting composition consisting of a gas(or foam) into a wellbore and into fractures or pore volumes of thesubterranean formation extending from the wellbore. The method furtherincludes introducing a second diverting composition including a fluidand a diverting agent into the subterranean formation. The methodfurther includes introducing a fracturing liquid (e.g., liquid) into thesubterranean formation, wherein the gas (or foam) is sufficientlypressurized within the fractures or pore volumes to cause the fracturingliquid to pressurize and fracture additional fractures or pore volumeswithin the subterranean formation.

Aspects of the present disclosure may also involve a method of treatinga subterranean formation penetrated by a wellbore. The method mayinclude introducing a first diverting composition comprising a foammixture of gas and liquid into features of the subterranean formationextending from the wellbore, the features comprising fractures or porevolumes. The method may further include introducing a second divertingcomposition comprising a fluid and a diverting agent into thesubterranean formation. The method may further include introducing afracturing liquid into the subterranean formation under sufficientpressure to fracture a portion of the subterranean formation and releasehydrocarbons from the subterranean formation, wherein the foam mixtureoccupies the features at a sufficient pressure to cause the fracturingliquid to be diverted to additional features of the subterraneanformation defined by the portion, the additional features comprisingadditional fractures or pore volumes.

Aspects of the present disclosure may also involve a method of treatinga subterranean formation penetrated by a wellbore. The method mayinclude introducing a composition comprising a substantiallycompressible substance into features of the subterranean formationextending from the wellbore, the features comprising fractures or porevolumes. The method may further include introducing a substantiallyincompressible substance into the subterranean formation undersufficient pressure to fracture a portion of the subterranean formationand release hydrocarbons from the subterranean formation, wherein thesubstantially compressible substance occupies the features at asufficient pressure to cause the substantially incompressible substanceto be diverted to additional features of the subterranean formationdefined by the portion, the additional features comprising additionalfractures and pore volumes.

In accordance with some embodiments of this disclosure is a method thatincludes injecting a gas into a wellbore at a rate from about 30 toabout 500,000 scf/min, where the injected gas occupies first and secondportions of a subterranean formation and thereafter, introducing afracturing liquid into the wellbore at a sufficient pressure to fracturethe second portion of the subterranean formation to a greater extentthan the first portion of the subterranean formation.

In accordance with some embodiments of this disclosure is a method thatincludes injecting a gas into a wellbore at a rate from about 30 toabout 500,000 scf/min and thereafter, introducing a fracturing liquidinto the wellbore at a sufficient pressure to fracture a subterraneanformation, and where: (i) the subterranean formation has a firsthydrocarbon production rate prior to the injecting of the gas; (ii) theinjected gas occupies some of the subterranean formation; (iii) thefractured subterranean formation has a second hydrocarbon productionrate; and (iv) the second hydrocarbon production rate is greater thanthe first hydrocarbon production rate.

In accordance with some embodiments of this disclosure is a method thatincludes injecting from about 1,000 scf to about 1,000,000,000 scf of agas into a wellbore, where the injected gas occupies first and secondportions of a subterranean formation, and thereafter, introducing afracturing liquid into the wellbore at a sufficient pressure to fracturethe second portion of the subterranean formation to a greater extentthan the first portion of the subterranean formation.

In accordance with some embodiments of this disclosure is a method thatincludes injecting from about 1,000 to about 1,000,000,000 scf of a gasinto a wellbore, and thereafter, introducing a fracturing liquid intothe wellbore at a sufficient pressure, and where: (i) the subterraneanformation has a first hydrocarbon production rate prior to the injectingof the gas; (ii) the injected gas occupies some of the subterraneanformation; (iii) the injected gas is injected at a sufficient pressureto fracture the subterranean formation; (iv) the fractured subterraneanformation has a second hydrocarbon production rate; and (iv) the secondhydrocarbon production rate is greater than the first hydrocarbonproduction rate.

In accordance with some embodiments of this disclosure is a method thatincludes injecting a gas into a wellbore, where the injected gasoccupies first and second portions of a subterranean formation and thegas injected in the first and second portions of the subterraneanformation comprises at least about 500 scf/lfCA over a lfCA from about 1foot to about 15 miles of the wellbore, and thereafter, introducing afracturing liquid into the wellbore at a sufficient pressure to fracturethe second portion of the subterranean formation to a greater extentthan the first portion of the subterranean formation.

In accordance with some embodiments of this disclosure is a method ofinjecting a gas into a wellbore at a rate from about 30 to 500,000scf/min, wherein the injected gas occupies a portion of a subterraneanformation and, thereafter, introducing a fracturing liquid into thewellbore at a sufficient pressure to fracture the subterraneanformation.

In accordance with some embodiments of this disclosure is a method ofinjecting a gas into a wellbore at a rate from about 30 to 500,000scf/min, wherein the injected gas occupies first and second portions ofa subterranean formation and, thereafter, introducing a fracturingliquid into the wellbore at a sufficient pressure to fracture thesubterranean formation.

In accordance with some embodiments of this disclosure is a method ofinjecting from about 1,000 to 1,000,000,000 scf of gas into a wellbore,wherein the injected occupies a portion of the subterranean formationand, thereafter, introducing a fracturing liquid into the wellbore at asufficient pressure to fracture the subterranean formation. Inaccordance with some embodiments of this disclosure is a method ofinjecting from about 1,000 to 1,000,000,000 scf of gas into a wellbore,wherein the injected occupies first and second portions of thesubterranean formation and, thereafter, introducing a fracturing liquidinto the wellbore at a sufficient pressure to fracture the subterraneanformation.

In accordance with some embodiments of this disclosure is a method thatincludes injecting a gas into a wellbore and thereafter, introducing afracturing liquid into the wellbore at a sufficient pressure to fractureat least some of a subterranean formation, where: (i) the injected gasoccupies a subterranean formation comprises at least about 500 scf/lfCAover a lfCA from about 1 foot to about 15 miles of the wellbore; (ii)the subterranean formation has a first hydrocarbon production ratebefore the injecting of the gas; (iii) the fractured subterraneanformation has a second hydrocarbon production rate; and (iv) the secondhydrocarbon production rate is greater than the first hydrocarbonproduction rate.

In some embodiments of the disclosure, the first portion of thesubterranean formation can contain first portion fractures. In someembodiments of the disclosure, the first portion of the subterraneanformation can contain first portion pore volumes. Furthermore, in someembodiments, the first portion of the subterranean formation can containfirst portion fractures and first portion pore volumes.

In some embodiments of the disclosure, the second portion of thesubterranean formation can contain second portion fractures. In someembodiments of the disclosure, the second portion of the subterraneanformation can contain second portion pore volumes. Furthermore, in someembodiments of the disclosure, the second portion of the subterraneanformation can contain second portion fractures and second portion porevolumes.

In some embodiments of the disclosure, the first portion of thesubterranean formation can be a low pressure stress zone. In someembodiments of the disclosure, the first portion of the subterraneanformation can be a first pressure stress zone. In some embodiments ofthe disclosure, the first portion of the subterranean formation can be apreviously hydraulic fractured zone. In some embodiments of thedisclosure, the first portion of the subterranean formation can be acombination of a low pressure stress zone and previously hydraulicfractured zone. Moreover, in some embodiments of the disclosure, thefirst portion of the subterranean formation can be one of low pressurestress zone, a previously hydraulic fractured zone, a combinationthereof.

In some embodiments of the disclosure, the second portion of thesubterranean formation can be a high pressure stress zone. In someembodiments of the disclosure, the second portion of the subterraneanformation can be a second pressure stress zone. In some embodiments ofthe disclosure, the second portion of the subterranean formation can bea non-previously hydraulic fractured zone. In some embodiments of thedisclosure, the second portion of the subterranean formation can be apreviously unstimulated zone. In some embodiments of the disclosure, thesecond portion of the subterranean formation can be a previously understimulated zone. In some embodiments of the disclosure, the secondportion of the subterranean formation can be one or more of a highpressure stress zone, a non-previously hydraulic fractured zone, apreviously unstimulated zone, and a previously under stimulated zone.Furthermore, in some embodiment of the disclosure, the second portion ofthe subterranean formation can be one of a high pressure stress zone, anon-previously hydraulic fractured zone, a previously unstimulated zone,a previously under stimulated zone or a combination thereof.

In accordance with some embodiments of the disclosure, the gas can be aninert gas. In accordance with some embodiments of the disclosure, thegas can be nitrogen (N2). In accordance with some embodiments of thedisclosure, the gas can be hydrogen (H2). In accordance with someembodiments of the disclosure, the gas can be methane (CH4). Inaccordance with some embodiments of the disclosure, the gas can beethane (CH3-CH3). In accordance with some embodiments of the disclosure,the gas can be propane (C3H8). In accordance with some embodiments ofthe disclosure, the gas can be butane (C4H10). In accordance with someembodiments of the disclosure, the gas can be carbon dioxide (CO2). Inaccordance with some embodiments of the disclosure, the gas can be oneor more of nitrogen (N2), hydrogen (H2), methane (CH4), ethane(CH3-CH3), propane (C3H8), butane (C4H10), carbon dioxide (CO2), andinert gas.

In accordance with some embodiments of the disclosure, the method caninclude the gas being in the gas phase during the injecting of the gasinto the wellbore. In accordance with some embodiments of thedisclosure, the method can include the gas being in the liquid phaseduring the injecting of the gas into the wellbore. In accordance withsome embodiments of the disclosure, the method can include the gas beingin the form of a foam during the injecting of the gas into the wellbore.Moreover, in accordance with some embodiments of the disclosure, themethod can include the gas being in the form of one or more of gasphase, liquid phase, foam, or combination thereof. In some embodiments,the foam can be more gas by volume than liquid by volume. Moreover, insome embodiments the foam can have no more than about 50 volume %liquid. Furthermore, in accordance with some embodiments, the foam canhave less gas by volume than liquid by volume.

In accordance with some embodiments of the disclosure, the method caninclude introducing, after the injecting of the gas but before theintroducing of the fracturing liquid, a diverting agent into thewellbore. Furthermore, in some embodiments, the diverting agent can beinjected at a sufficient pressure to occupy at least some of the firstportion of the subterranean formation. Moreover, the first portion ofthe subterranean formation can contain one or more of first portionfractures and first portion pore volumes. In some embodiments, thediverting agent can occupy at least some of one or more of the firstportion fractures and the first portion pore volumes. In someembodiments, the diverting agent occupies at least of most the firstportion fractures and the first portion pore volumes. In accordance withsome embodiments of the disclosure, the introducing of the divertingagent can begin immediately after terminating the injection of the gasinto the wellbore. The diverting agent can be in some embodimentsselected from the group consisting essentially of a chemical divertingagent, a mechanical diverting agent, a degradable fiber, benzoic acid,or a combination thereof. Moreover, the diverting agent can be achemical diverting agent. The diverting agent can be, in someembodiments, a mechanical diverting agent. It can be appreciated that insome embodiments, the diverting agent can be a degradable divertingagent. Furthermore, the diverting agent can be benzoic acid or a benzoicacid derivative.

In accordance with some embodiments of the disclosure, the method caninclude maintaining a dwell period between the injecting of the gas inthe wellbore and the introducing of the fracturing liquid into the wellbore. In some embodiments, the dwell period can be less than one hour.In some embodiments, the dwell period can be less than 24 hours. In someembodiments, the dwell period can be more than 24 hours. In someembodiments, the dwell period can be one of less than one hour, lessthan 24 hours, and more than 24 hours.

In some embodiments of the disclosure, the gas can be injected into thewellbore at a rate of about 30 to about 500,000 scf/min.

In some embodiments of the disclosure, the gas injected into thewellbore can be from about 1,000 to about 1,000,000,000 scf. Moreover,in some embodiments, the gas injected into the wellbore can be fromabout 1,000 to about 100,000,000 scf. Furthermore, the gas injected intothe wellbore can be, in some embodiments, more than about 1×109 scf.

In some embodiments of the disclosure, the gas injected in the first andsecond portions of the subterranean formation can be at least about 500scf/lfCA over a lfCA from about 1 foot to about 15 miles of thewellbore. Moreover, in some embodiments, the gas injected in the firstand second portions of the subterranean formation can be no more thanabout 5, scf/lfCA over a lfCA from about 1 foot to about 15 miles of thewellbore.

In accordance with some embodiments of the disclosure, the secondportion of the subterranean formation can commonly have a pressure of atleast about 5% more than the first portion of the subterraneanformation. More commonly, the second portion of the subterraneanformation can have a pressure of at least about 10% more, even morecommonly a pressure of at least about 50% more, yet even more commonly apressure of at least about 100% more, yet even more commonly a pressureof at least about 200% more, yet even more commonly a pressure of atleast about 500% more, yet even more commonly a pressure of at leastabout 1,000% more, yet even more commonly a pressure of at least about2,500% more, yet even more commonly a pressure of at least about 5,000%more, yet even more commonly a pressure of at least about 7,500% more,or even yet more commonly a pressure of at least about 10,000% more thanthe first portion of the subterranean formation.

Aspects of the present disclosure involve a method of treating asubterranean formation penetrated by a wellbore. The method includesintroducing a composition comprising a gas (or foam) into features ofthe subterranean formation extending from the wellbore, the featuresincluding fractures or pore volumes. The method further includesintroducing a diverting composition including a fluid and a divertingagent into the features of the subterranean formation extending from thewellbore. The method further includes introducing a carrier fluid intothe subterranean formation under sufficient pressure to fracture aportion of the subterranean formation and release hydrocarbons from thesubterranean formation, wherein the gas occupies the features at asufficient pressure to cause the carrier fluid to be diverted toadditional features of the subterranean formation defined by theportion, the additional features including additional fractures or porevolumes.

Aspects of the present disclosure may also involve a method of treatinga subterranean formation penetrated by a wellbore. The method mayinclude introducing a first diverting composition consisting of a gas(or foam) into a wellbore and into fractures or pore volumes of thesubterranean formation extending from the wellbore. The method furtherincludes introducing a second diverting composition including a fluidand a diverting agent into the subterranean formation. The methodfurther includes introducing a carrier fluid (e.g., liquid) into thesubterranean formation, wherein the gas (or foam) is sufficientlypressurized within the fractures or pore volumes to cause the carrierfluid to pressurize and fracture additional fractures or pore volumeswithin the subterranean formation.

Aspects of the present disclosure may also involve a method of treatinga subterranean formation penetrated by a wellbore. The method mayinclude introducing a first diverting composition comprising a foammixture of gas and liquid into features of the subterranean formationextending from the wellbore, the features comprising fractures or porevolumes. The method may further include introducing a second divertingcomposition comprising a fluid and a diverting agent into thesubterranean formation. The method may further include introducing acarrier fluid into the subterranean formation under sufficient pressureto fracture a portion of the subterranean formation and releasehydrocarbons from the subterranean formation, wherein the foam mixtureoccupies the features at a sufficient pressure to cause the carrierfluid to be diverted to additional features of the subterraneanformation defined by the portion, the additional features comprisingadditional fractures or pore volumes.

Aspects of the present disclosure may also involve a method of treatinga subterranean formation penetrated by a wellbore. The method mayinclude introducing a composition comprising a substantiallycompressible substance into features of the subterranean formationextending from the wellbore, the features comprising fractures or porevolumes. The method may further include introducing a substantiallyincompressible substance into the subterranean formation undersufficient pressure to fracture a portion of the subterranean formationand release hydrocarbons from the subterranean formation, wherein thesubstantially compressible substance occupies the features at asufficient pressure to cause the substantially incompressible substanceto be diverted to additional features of the subterranean formationdefined by the portion, the additional features comprising additionalfractures and pore volumes.

The present disclosure can have advantages over current practice. Forexample, it can divert effectively the carrier fluid from a selectedarea of the well bore (or formation), such as the low stress area,thereby improving well economics and increasing recoverable reserves. Itcan divert the carrier fluid in the absence or substantial absence ofsolid particulates, which can be detrimental to well health andproductivity, and be used in any well bore orientation, whetherhorizontal or vertical. It can change the fracture pressure gradient ofa down hole formation by making the formation more brittle and thereforeeasier to fracture by the carrier fluid. While not wishing to be boundby any theory, it is believed that the gas (or foam) increases theformation pore pressure and substantially equalizes the pore pressureacross the various formations exposed by the well bore.

Aspects of the present disclosure involve a method of treating asubterranean formation penetrated by a wellbore. The method includesintroducing a composition including a gas into features of thesubterranean formation extending from the wellbore. The featuresincluding fractures or pore volumes. This step is followed byintroducing a carrier fluid into the subterranean formation undersufficient pressure to fracture a portion of the subterranean formationand release hydrocarbons from the subterranean formation. The gas mayoccupy the features at a sufficient pressure to cause the carrier fluidto be diverted to additional features of the subterranean formationdefined by the portion. The additional features may include additionalfractures or pore volumes.

Aspects of the present disclosure may also involve a method of treatinga subterranean formation penetrated by a wellbore. The method includesintroducing a diverting composition consisting of a gas into a wellboreand into fractures or pore volumes of the subterranean formationextending from the wellbore and introducing a carrier fluid into thesubterranean formation, the gas being sufficiently pressurized withinthe fractures or pore volumes to cause the carrier fluid to pressurizeadditional fractures or pore volumes within the subterranean formation.

Aspects of the present disclosure may also involve a method of treatinga subterranean formation penetrated by a wellbore. The method includesintroducing a diverting composition including a foam mixture of gas andliquid into features of the subterranean formation extending from thewellbore. The features may include fractures or pore volumes. The methodmay additionally include introducing a carrier fluid into thesubterranean formation under sufficient pressure to fracture a portionof the subterranean formation and release hydrocarbons from thesubterranean formation. The foam mixture may occupy the features at asufficient pressure to cause the carrier fluid to be diverted toadditional features of the subterranean formation defined by theportion. The additional features may include additional fractures orpore volumes.

Aspects of the present disclosure may also involve a method of treatinga subterranean formation penetrated by a wellbore. The method mayinclude introducing a composition including a substantially compressiblesubstance into features of the subterranean formation extending from thewellbore. The features may include fractures or pore volumes. The methodmay additionally include introducing a substantially incompressiblesubstance into the subterranean formation under sufficient pressure tofracture a portion of the subterranean formation and releasehydrocarbons from the subterranean formation. The substantiallycompressible substance may occupy the features at a sufficient pressureto cause the substantially incompressible substance to be diverted toadditional features of the subterranean formation defined by theportion. The additional features may include additional fractures andpore volumes.

These and other advantages will be apparent from the disclosure of theaspects, embodiments, and configurations contained herein.

As used herein, “at least one”, “one or more”, and “and/or” areopen-ended expressions that are both conjunctive and disjunctive inoperation. For example, each of the expressions “at least one of A, Band C”, “at least one of A, B, or C”, “one or more of A, B, and C”, “oneor more of A, B, or C” and “A, B, and/or C” means A alone, B alone, Calone, A and B together, A and C together, B and C together, or A, B andC together. When each one of A, B, and C in the above expressions refersto an element, such as X, Y, and Z, or class of elements, such as X1-Xn,Y1-Ym, and Z1-Zo, the phrase is intended to refer to a single elementselected from X, Y, and Z, a combination of elements selected from thesame class (e.g., X1 and X2) as well as a combination of elementsselected from two or more classes (e.g., Y1 and Zo).

It is to be noted that the term “a” or “an” entity refers to one or moreof that entity. As such, the terms “a” (or “an”), “one or more” and “atleast one” can be used interchangeably herein. It is also to be notedthat the terms “comprising”, “including”, and “having” can be usedinterchangeably.

The term “means” as used herein shall be given its broadest possibleinterpretation in accordance with 35 U.S.C., Section 112, Paragraph 6.Accordingly, a claim incorporating the term “means” shall cover allstructures, materials, or acts set forth herein, and all of theequivalents thereof. Further, the structures, materials or acts and theequivalents thereof shall include all those described in the summary ofthe invention, brief description of the drawings, detailed description,abstract, and claims themselves.

Unless otherwise noted, all component or composition levels are inreference to the active portion of that component or composition and areexclusive of impurities, for example, residual solvents or by-products,which may be present in commercially available sources of suchcomponents or compositions.

It should be understood that every maximum numerical limitation giventhroughout this disclosure is deemed to include each and every lowernumerical limitation as an alternative, as if such lower numericallimitations were expressly written herein. Every minimum numericallimitation given throughout this disclosure is deemed to include eachand every higher numerical limitation as an alternative, as if suchhigher numerical limitations were expressly written herein. Everynumerical range given throughout this disclosure is deemed to includeeach and every narrower numerical range that falls within such broadernumerical range, as if such narrower numerical ranges were all expresslywritten herein. By way of example, the phrase from about 2 to about 4includes the whole number and/or integer ranges from about 2 to about 3,from about 3 to about 4 and each possible range based on real (e.g.,irrational and/or rational) numbers, such as from about 2.1 to about4.9, from about 2.1 to about 3.4, and so on.

The preceding is a simplified summary of the disclosure to provide anunderstanding of some aspects of the disclosure. This summary is neitheran extensive nor exhaustive overview of the disclosure and its variousaspects, embodiments, and configurations. It is intended neither toidentify key or critical elements of the disclosure nor to delineate thescope of the disclosure but to present selected concepts of thedisclosure in a simplified form as an introduction to the more detaileddescription presented below. As will be appreciated, other aspects,embodiments, and configurations of the disclosure are possibleutilizing, alone or in combination, one or more of the features setforth above or described in detail below. Also, while the disclosure ispresented in terms of exemplary embodiments, it should be appreciatedthat individual aspects of the disclosure can be separately claimed.

BRIEF DESCRIPTION OF THE DRAWINGS

The accompanying drawings, which are incorporated in and constitute apart of the specification, illustrate embodiments of the disclosure andtogether with the general description of the disclosure given above andthe detailed description given below, serve to explain the principles ofthe disclosure.

FIG. 1 depicts a well undergoing a stimulation treatment according tothe prior art, and a side view of a hydraulic fracturing operationshowing high and low stress zones;

FIGS. 2A and 2B depict a well undergoing a stimulation treatmentaccording to some embodiments of present disclosure;

FIG. 3 depicts a process according to some embodiments of the presentdisclosure;

FIG. 4 is a side view of a horizontal drilling operation utilizing thediversion technique described herein where a gas (or foam) is introducedinto the well;

FIG. 5 is a side view of the horizontal drilling operation utilizing thediversion technique described herein where a carrier liquid isintroduced into the well;

FIG. 6 is a flowchart illustrating the steps in utilizing the diversiontechnique described herein;

FIG. 7 is a flowchart illustrating another set of steps in utilizing thediversion technique described herein;

FIG. 8 is a flowchart illustrating yet another set of steps in utilizingthe diversion technique described herein;

FIG. 9 is a flowchart illustrating another set of steps utilizing thediversion technique described herein;

FIG. 10 depicts a multi-well configuration according to an embodiment;

FIG. 11 depicts a multi-well configuration according to an embodiment;

FIG. 12 depicts a multi-well configuration according to an embodiment;

FIG. 13 depicts a multi-well configuration according to an embodiment;

FIG. 14 depicts a multi-well configuration according to an embodiment;

FIG. 15 is a side view of a hydraulic fracturing operation showing highand low stress zones;

FIG. 16 is a side view of a horizontal drilling operation utilizing thediversion technique described herein where a gas is introduced into thewell;

FIG. 17 is a side view of the horizontal drilling operation utilizingthe diversion technique described herein where a carrier liquid isintroduced into the well;

FIG. 18 is a flowchart illustrating the steps in utilizing the diversiontechnique described herein;

FIG. 19 is a flowchart illustrating another set of steps in utilizingthe diversion technique described herein; and

FIG. 20 is a flowchart illustrating yet another set of steps inutilizing the diversion technique described herein.

DETAILED DESCRIPTION

In recent years, hydraulic fracturing has become a widely-used wellstimulation technique to increase well production and access previouslyuncaptured hydrocarbons. Hydraulic fracturing involves hydraulicallyfracturing the subterranean formation with a pressurized liquid orcarrier, liquid, containing, water, proppant (e.g., sand or man-madealternative), and/or chemicals, that is injected into a wellbore. Uponpressurizing the wellbore with the carrier liquid, the formationfractures or cracks and the carrier fluid can leave behind proppant,which allows the hydrocarbons to flow more freely through the fracturesand into the wellbore to be recovered. In some instances, a downholeelectric submersible pump may pump the hydrocarbons from the reservoirto overcome the hydrostatic head pressure of the hydrocarbons, or thehydrocarbons may flow freely up the wellbore without assistance.

As seen in FIG. 1, which is a side view of a horizontal drillingoperation 100 utilizing hydraulic fracturing, a pressurized liquid 102may cause multiple fractures 104 within the subterranean formation 106.Fractures 104 formed by the pressurized liquid 102 can be of varyingsizes. Accordingly, larger fractures or pore volumes 108 may cause alower stress zone 110 within the formation such that upon stimulationand re-stimulation of the well the carrier liquid 102 tends toconcentrate in these lower stress zones 110. These lower stress zones110 can be caused by hydrocarbon depletion, lower pore pressure, and/orhigher permeability of the reservoir 106. Permeability of the reservoircan, in part, depend on the extensiveness of fractures and/or pores, andthe interconnectivity of the fractures and/or pores that create pathwaysfor hydrocarbons to flow. As a result of the lower stress zones, thehydrocarbons are more likely to flow through these larger fractures orpore volumes 108, and/or those with interconnectivity, until depletion.The fractures and/or pore volumes 104 of finer sizes 112 and/or thoselacking interconnectivity tend to be concentrated in higher stress zones114 such that the carrier liquid 102 is less likely to effectivelyhydraulically fracture those higher stress zones and thus influence theflow of hydrocarbons in these regions upon stimulation orre-stimulation. This is in part, because the pressure of the carrierliquid 102 is generally evenly distributed along the wellbore in thetreated area such that the carrier liquid I 02 remains concentrated inthe lower stress zones 110 rather than the higher stress zones 114. Thehigher stress zones 114, in contrast to the lower stress zones 110, canbe caused by higher pore pressure, ineffective hydraulically fracturedregions, lower permeability of the reservoir 106, or generally lessdepleted portions of the reservoir 106. As such, the carrier liquid 102tends to not affect the higher stress zones 114, which may containhydrocarbons, unless additional systems and methods are employed.

In subsequent well treatments or in initial well, treatments, divertersystems may be used to divert the carrier liquid 102 from the lowerstress zones 110, which may be depleted from previous treatments, to thepreviously un-accessed, higher stress zones 114. Diverting the carrierliquid 102 into these higher stress zones 114 may be difficult overlarge areas of the wellbore and reservoir for a number of reasons. Innew wells, the difficulty may be due to differences in stresses fromdifferent lithologies or from different reservoir characteristics alongthe well. Differences in stress can be due to natural in-situ stressconditions or man-made activities such as well stimulation or depletionof fluids. In previously stimulated wells, the difficulty may be due toadequately blocking the fractures and/or pore volume 108 in the lowerstress zones 110 such that the carrier liquid 102 pressurizes thefractures 112 of the higher stress zones 114. Diverter systems includethe use of particulates (e.g., polymers) and chemical diverters withinthe carrier liquid 102, among other methods, to block either thewellbore or the formation near the wellbore so that a portion of thecarrier liquid 102 may be diverted to the fractures 112 in the higherstress zones 114 and also create new fractures in the higher stresszones.

Aspects of the presently disclosed technology involve a diversiontechnique for use in vertical, deviated, or horizontal wells undergoinga stimulation process (e.g., initial stimulation or re-stimulation) todivert a carrier liquid from treating previously stimulated areas (i.e.,lower stress zones of the formation) and to force the carrier liquid totreat previously unstimulated areas (i.e., higher stress zones of theformation). The methods disclosed provide cost-effective means forimproving the well production. After a wellbore is drilled andcompleted, stimulation operations are usually performed to enhancehydrocarbon (e.g. gas, oil, etc.) production into the wellbore and toenhance extraction of the hydrocarbons from the subterranean formation.Current diversion techniques use liquid or solid forms, such as chemicalsolutions (e.g., a borate solution) or, particulates (e.g., polymersspheres), which can be costly and potentially ineffective in divertingfluid to the higher stress regions/zones of the reservoir. Additionally,liquid- and solid-form diverters can be problematic as they leaveresidue that can damage the subterranean formation and can lead toinhibited production from the well. In contrast, the methods of thepresent disclosure are cost effective, operationally feasible based oncurrent equipment available to the industry, and can enhance the rate ofextraction of the hydrocarbons. In particular, the use of a gas as thediversion medium allows for greater filling of the reservoir in lowerstress zones such that a carrier liquid can be more efficiently divertedto the higher stress zones of the reservoir. The use of a gas as thediversion medium also has advantages in that no residue remains and thegas can be recovered during flowback. In certain instances, the gas maybe recovered during flowback can be reused, recycled, or marketed.

Further, FIG. 1 depicts a side view of a horizontal drilled well 100treated according to a method of the prior art utilizing a fracturingliquid 102 to produce multiple fractures 104 within a subterraneanformation 106. The multiple fractures 104 produced by the pressurizedliquid 102 can vary in size. Typically, low stress zones 110 containlarger fractures and/or pore volumes 108 than high stress zones 114.During stimulation, re-stimulation or re-fracturing the fracturingliquid 102 typically tends to concentrate in the larger fractures and/orlarger pore volumes 108 of low stress zones 110. These low stress zones110 tend to be zones of hydrocarbon depletion, lower pore pressure,higher permeability, or a combination thereof. Permeability of thereservoir can, in part, depend on the extensiveness andinterconnectivity of the fractures and/or pores. Moreover, hydrocarbonflow typically depends on the extensiveness and/or interconnectivity ofthe fractures and/or pores that create pathways for the hydrocarbon. Thehydrocarbons are more likely to flow through these larger and/or moreinterconnected fractures and/or pore volumes 108. The high stress zones114 tend to be zones having finer and/or less interconnected fracturesand/or pore volumes 112 such that the fracturing liquid 102 is lesslikely to hydraulically fracture these high stress zones 114. Thesefiner and/or less interconnected fractures and/or pore volumes 112 caninfluence the flow of hydrocarbons in these regions upon stimulation orre-stimulation. This is in part, because the pressure of the fracturingliquid 102 is generally distributed along the wellbore 118 in thetreated area such that the pressurized fracturing liquid 102 can achievethe fracture gradient in the low stress zones 110 but not the highstress zones 114. The high stress zones 114, in contrast to the lowstress zones 110, can have one or more of higher pore pressure,ineffective hydraulically fractured regions, lower permeability, orgenerally less depleted portions of the subterranean formation 106. Assuch, the fracturing liquid 102 is one or more of less likely topermeate these lower permeability and/or generally less depletedportions of the subterranean formation 106 and less likely to achievethe fracture gradient threshold in these higher pore pressure, highstress zones 114. Accordingly, unless additional systems and methods areemployed the hydrocarbons in these high stress zones 114 are difficultto produce due to high pore pressures and/or low permeability of thesezones.

In subsequent or initial well treatments diverter systems can be used todivert the fracturing liquid 102 from the low stress zones 110, whichcan be depleted from previous treatments, to the previously un-accessed,high stress zones 114. Diverting the fracturing liquid 102 into thesehigh stress zones 114 can be difficult over large areas of the wellbore118 and reservoir for a number of reasons. In new wells, the difficultycan be due to differences in stresses from different lithologies or fromdifferent reservoir characteristics along the wellbore 118. Differencesin stress can be due to natural in-situ stress conditions or man-madeactivities such as well stimulation or depletion of fluids, such ashydrocarbons. In previously stimulated wells, the difficulty can be dueto adequately blocking the fractures and/or pore volume 108 in the lowstress zones 110 such that the fracturing liquid 102 pressurizes thehigh stress zones 114. Diverter systems can include the use ofparticulates (e.g., inorganic and/or organic polymeric particulates) andchemical diverters within the fracturing liquid 102, among othermethods, to block either the wellbore 118 or the subterranean formation106 near the wellbore 118 so that a portion of the fracturing liquid 102can be diverted to the high stress zones 114 and create new fractures112 in the high stress zones 114.

Aspects of the presently disclosed technology involve a diversiontechnique for use in vertical, deviated, or horizontal wells undergoinga stimulation process (e.g., initial stimulation or re-stimulation). Thepresently disclosed technology can divert a fracturing liquid fromtreating one or more previously stimulated areas (i.e., low stress zonesof the formation) to one or more previously unstimulated zones (i.e.,high stress zones of the formation). As used herein a previouslyunstimulated area can refer to one or more of a previously unstimulatedhigh stress zone, a previously unstimulated low stress zone, apreviously partially stimulated high stress zone, a previously partiallystimulate low stress zone, or a combination thereof.

The methods disclosed herein can provide cost-effective means forimproving hydrocarbon production from a well. After a wellbore isdrilled and completed, stimulation operations are usually performed toenhance hydrocarbon (e.g. gas, oil, etc.) production into the wellboreand to enhance extraction of hydrocarbons from the subterraneanformation 206. It can be appreciated that the above-described initialwell treatments and/or subsequent well treatments can direct afracturing liquid 202 to one or more previously unstimulated zones. Thepreviously unstimulated zones can be high stress zones 214. Aspects ofthe present disclosure can involve a technique for use in vertical,deviated, or horizontal wells undergoing a stimulation process (e.g.,initial stimulation or re-stimulation) to direct a fracturing liquid 202to treat a previously unstimulated zone.

Current diversion techniques use liquid or solid forms, such as chemicalsolutions (e.g., a borate solution) or, particulates (e.g., polymersspheres). The methods of the present disclosure are cost effective,operationally feasible based on current equipment available to theindustry, and can enhance the rate of extraction of the hydrocarbons. Inparticular, the use of a gas (or foam) as the diversion medium allowsfor greater filling of the reservoir in low stress zones such that afracturing liquid can be more efficiently diverted to the higher stresszones of the reservoir. The use of a gas (or foam) as the diversionmedium also has advantages in that the gas (or gas component of thefoam) can be recovered during flowback. In certain instances, the gas(or gas component of the foam) can be recovered during flowback can bereused, recycled, or marketed.

Moreover, the methods of the present disclosure can use one of a gas asthe medium for treating the previously unstimulated zones. As usedherein the gas can generally refer to any chemical composition in thegaseous phase including but not limited to a single phase gaseoussystem, a foam (that is, a gas entrapped within a liquid), and acombination thereof (that is, a system having some gas entrapped withina liquid and some gas not entrapped within a liquid). It is believedthat the gas can more effectively penetrate one or both of the fracturesand pore volumes of the previously unstimulated zones than thefracturing liquid 202. That is, the gas can more easily fill andpressurize the one or both of the factures and pore volumes of thepreviously unstimulated zones more easily than the fracturing liquid202. Furthermore, it is believed that one or both of the factures andpore volumes of the previously unstimulated zones filled and/orpressurized with a gas can be efficiently stressed and fractured.

In accordance with some embodiments of the disclosure, the method caninclude stimulating a well and reservoir by alternating orsimultaneously introducing a gas diverter and a conventional diverter(e.g., chemical, biological, or mechanical diverter systems known andunknown). In certain instances, using a conventional diverter along withthe gas diverter, described herein, could produce better economicresults than either one could produce on their own. In some embodiments,the method includes introducing a gas and a conventional diverter systeminto a reservoir. The gas and conventional diverter system can beintroduced simultaneously or one after the other in any order and/orcombination. While not wanting to be bound by example: the gas can beintroduced prior to the conventional diverter system; or a first portionof the gas can be introduced prior to the conventional diverter systemand a second portion of gas can be introduce after the conventionaldiverter system; or the convention diverter system can be introducedprior to gas being introduced.

FIGS. 2A and 2B depict a side view of a well configuration 200 inaccordance some embodiments of the present disclosure treated accordingto process 300 depicted in FIG. 3. In step 310, a gas (in any of theforms as described herein) 216 is introduced and/or injected into a welland reservoir 220 comprising subterranean formation 206. Thesubterranean formation 206 may include any type of rock and/or mineralor combination and/or mixture of any known rocks and minerals. Thesubterranean formation 206 can comprise one or more of sedimentaryrocks, igneous rocks, and metamorphic rocks. Non-limiting examples ofsedimentary rocks can include sandstone, limestone, and shale. Igneousrocks can include without limitation granite and andesite. Metamorphicrocks can include without limitation gneiss, slate, marble, schist, andquartzite. In some embodiments, the subterranean formation 206 cancomprise a shale formation, a clay formation, a sandstone formation, alimestone formation, a carbonate formation, a granite formation, amarble formation, a coal bed, or a combination thereof.

The gas 216 is introduced and/or injected into the subterraneanformation 206 at sufficient pressure to pressurize first portionfractures and pore volumes 208. In accordance with some embodiments thegas 216 can also infiltrate second portion fractures and pore volumes212. Generally, the first portion fractures and pore volumes 208 arecontained in first stress zone 210 and the second portion fractures andpore volumes 212 are contained in second stress zone. The first stresszone 210 is typically of lower stress than the second stress zone 214.Stated another way, the second stress zone 214 is usually of higherstress than the first stress zone 210.

The injection pressure of the gas 216 depends on the fracture gradientof the low stress zone 210. As will be appreciated, the fracturegradient is the pressure required to induce a facture in the rock, suchas the subterranean formation 206, at a given depth, as such thefracture gradient units are typically expressed in psi/ft or kPa/m. Thefracture gradient can be a function of many factors including but notlimited to overburden stress, Poisson's ratio of the formation (rock),pore pressure gradient, formation (rock) matrix stress coefficient, andmatrix stress. There are many techniques for determining the fracturegradient of a subterranean formation 206, such as the pseudo-overburdenstress method, effective stress method, leak-off tests, Hubbert & Willistechnique, Matthews & Kelly technique, and Ben Eaton technique.Typically, the gas 216 is injected into the wellbore 218 at a pressurethat is less than the fracture gradient(s) of the first 210 and/orsecond 214 stress zones (and/or other subsurface formations along thewellbore 218) to inhibit (further) fracturing of one or more of thesezones. In accordance with some embodiments, the injection pressure ofthe gas 216 is generally maintained below the fracture gradient thesubterranean formation 206. More generally, the injection pressure ofthe gas 216 is maintained below the fraction gradient of one or more thefirst 210 and second 214 stress zones. Even more generally the injectionpressure of the gas 216 is maintained below the fracture gradient ofsubterranean formation 206 including the first 210 and second 214 stresszones during substantially the entire duration of injecting the gas 216.Typically, the injection pressure of the gas 216 is maintained below thefracture gradient of subterranean formation 206 including the first 210and second 214 stress zones during substantially at least about 50% ofthe entire duration of injecting the gas 216. More typically, at leastabout 75%, even more typically at least about 90%, and yet even moretypically at least about 95% of the entire duration of the injecting thegas 216.

In some embodiments of step 310, the injecting of gas 216 is continueduntil a desired pressure is reached within the well and/or reservoir220. Typically, the injecting of the gas 216 is continued to a pressureof no more than the fracture gradient. More typically, the gas 216 iscontinued to a pressure of one of no more than about 99% of the fracturegradient, even more typically to a pressure of no more than about 98% ofthe fracture gradient, yet even more typically to a pressure of no morethan about 97% of the fracture gradient, still yet even more typicallyto a pressure of no more than about 96% of the fracture gradient, stillyet even more typically to a pressure of no more than about 95% of thefracture gradient, still yet even more typically to a pressure of nomore than about 90% of the fracture gradient, still yet even moretypically to a pressure of no more than about 85% of the fracturegradient, still yet even more typically to a pressure of no more thanabout 80% of the fracture gradient, still yet even more typically to apressure of no more than about 75% of the fracture gradient, still yeteven more typically to a pressure of no more than about 70% of thefracture gradient, still yet even more typically to a pressure of nomore than about 65% of the fracture gradient, still yet even moretypically to a pressure of no more than about 60% of the fracturegradient, still yet even more typically to a pressure of no more thanabout 55% of the fracture gradient, still yet even more typically to apressure of no more than about 50% of the fracture gradient, still yeteven more typically to a pressure of no more than about 45% of thefracture gradient, still yet even more typically to a pressure of nomore than about 40% of the fracture gradient, still yet even moretypically to a pressure of no more than about 35% of the fracturegradient, still yet even more typically to a pressure of no more thanabout 30% of the fracture gradient, still yet even more typically to apressure of no more than about 25% of the fracture gradient, still yeteven more typically to a pressure of no more than about 20% of thefracture gradient, still yet even more typically to a pressure of nomore than about 15% of the fracture gradient, still yet even moretypically to a pressure of no more than about 10% of the fracturegradient, still yet even more typically to a pressure of no more thanabout 9% of the fracture gradient, still yet even more typically to apressure of no more than about 8% of the fracture gradient, still yeteven more typically to a pressure of no more than about 7% of thefracture gradient, still yet even more typically to a pressure of nomore than about 6% of the fracture gradient, still yet even moretypically to a pressure of no more than about 5% of the fracturegradient, still yet even more typically to a pressure of no more thanabout 4% of the fracture gradient, still yet even more typically to apressure of no more than about 3% of the fracture gradient, still yeteven more typically to a pressure of no more than about 2% of thefracture gradient, or yet still even more typically to a pressure of nomore than about 1% of the fracture gradient.

Factors that can affect the volume of gas 216 to be introduced in thewellbore 218 include the size (that is volume) of the subterraneanformation 206 in fluid communication with wellbore 218, the size(volume) of the depleted regions of the subterranean formation 206, thesize (volume) the pore volumes and fractures, leak off rate of the gas216, and the reservoir pressure of the subterranean formation 206 priorto the injection of gas 216.

For instance, in some embodiments, the volume of the gas 216 injectedinto the subterranean formation 206 can range from about 1,000 standardcubic feet (scf) to about 100,000,000 scf. In some embodiments, thevolume of gas 216 injected into the subterranean formation 206 can begreater than about 1×109 scf. Typically, the volume of gas injected intothe subterranean formation 206 is typically at least about 50,000 scf,more typically at least about 100,000 scf, even more typically at leastabout 150,000 scf, yet even more typically at least about 200,000 scf,still yet even more typically at least about 250,000 scf, still yet evenmore typically at least about 300,000 scf, still yet even more typicallyat least about 350,000 scf, still yet even more typically at least about400,000 scf, still yet even more typically at least about 450,000 scf,still yet even more typically at least about 550,000 scf, still yet evenmore typically at least about 600,000 scf, still yet even more typicallyat least about 650,000 scf, still yet even more typically at least about700,000 scf, still yet even more typically at least about 750,000 scf,still yet even more typically at least about 800,000 scf, still yet evenmore typically at least about 850,000 scf, still yet even more typicallyat least about 900,000 scf, still yet even more typically at least about950,000 scf, still yet even more typically at least about 1,000,000 scf,still yet even more typically at least about 2,000,000 scf, still yeteven more typically at least about 3,000,000 scf, still yet even moretypically at least about 4,000,000 scf, still yet even more typically atleast about 5,000,000 scf, still yet even more typically at least about6,000,000 scf, still yet even more typically at least about 7,000,000scf, still yet even more typically at least about 8,000,000 scf, stillyet even more typically at least about 9,000,000 scf, and yet still yeteven more typically at least about 10,000,000 scf. Commonly, the volumeof gas 216 is no more than about 200,000,000 scf, more commonly no morethan about 300,000,000 scf, even more commonly no more than about400,000,000 scf, yet even more commonly no more than about 500,000,000scf, and still yet it is within the scope of some embodiments of thisinvention to inject up to about 1,000,000,000 scf.

Stated another way, the volume of gas 216 injected into the subterraneanformation 206 can be expressed in terms of standard cubic feet of gas(scf) per net linear feet of the wellbore 218 in contact with and influid communication with the subterranean formation 206 (lf_(CA)).Typically, the volume of gas 216 injected into the subterraneanformation 206 is at least about 500 scf/lf_(CA), more typically at leastabout 525 scf/lf_(CA), even more typically at least about 550scf/lf_(CA), yet even more typically at least about 575 scf/lf_(CA),still yet even more typically at least about 600 scf/lf_(CA), still yeteven more typically at least about 625 scf/lf_(CA), still yet even moretypically at least about 650 scf/lf_(CA), still yet even more typicallyat least about 675 scf/lf_(CA), still yet even more typically at leastabout 700 scf/lf_(CA), still yet even more typically at least about 725scf/lf_(CA), and yet still even more typically at least about 750scf/lf_(CA). Commonly, in some embodiments, the volume of gas 216injected into the subterranean formation 206 is no more than about 5,000scf/lf_(CA), even more commonly no more than about 4,750 scf/lf_(CA),yet even more commonly no more than about 4,500 scf/lf_(CA), still yeteven more commonly no more than about 4,250 scf/lf_(CA), still yet evenmore commonly no more than about 4,000 scf/lf_(CA), still yet even morecommonly no more than about 3,750 scf/lf_(CA), still yet even morecommonly no more than about 3,500 scf/lf_(CA), still yet even morecommonly no more than about 3,250 scf/lf_(CA), still yet even morecommonly no more than about 3,000 scf/lf_(CA), still yet even morecommonly no more than about 2,900 scf/lf_(CA), still yet even morecommonly no more than about 2,800 scf/lf_(CA), still yet even morecommonly no more than about 2,700 scf/lf_(CA), still yet even morecommonly no more than about 2,600 scf/lf_(CA), and yet still even morecommonly no more than about 2,500 scf/lf_(CA).

In accordance with some embodiments, the gas 216 can be injected at arate of about 30 to about 500,000 scf/min. Generally, the gas 216 can beinjected at a rate of about 10,000 to about 20,000 scf/min. Typically,the injection rate of the gas 216 is about 30 scf/min or more, moretypically about 50 scf/min or more, even more typically about 100scf/min or more, yet even more typically about 200 scf/min or more,still yet even more typically about 300 scf/min or more, still yet evenmore typically about 400 scf/min or greater, still yet even moretypically about 500 scf/min or more, still yet even more typically about600 scf/min or more, still yet even more typically about 700 scf/min ormore, still yet even more typically about 800 scf/min or more, still yeteven more typically about 900 scf/min or more, and yet still even moretypically about 1,000 scf/min or more. Commonly, the gas 216 can beinjected at a rate of no more than about 500,000 scf/min, more commonlyat rate of no more than about 450,000 scf/min, even more commonly atrate of no more than about 400,000 scf/min, yet even more commonly atrate of no more than about 350,000 scf/min, still yet even more commonlyat rate of no more than about 300,000 scf/min, still yet even morecommonly at rate of no more than about 250,000 scf/min, still yet evenmore commonly at rate of no more than about 200,000 scf/min, still yeteven more commonly at rate of no more than about 150,000 scf/min, andyet still even more commonly at rate of no more than about 100,000scf/min.

The gas 216 can include any number of gasses. For example, the gas 216can comprise nitrogen, hydrogen, methane, ethane, propane, butane,carbon dioxide, any inert gas, or any combination thereof. The gas 216can be injected into the well and reservoir 220 in a number of ways. Insome embodiments, the gas 216 can be delivered to wellhead 226 by one ormore of a storage truck, a pipeline, a storage tank, a gas producingwell, or other suitable gas supply sources. It can be appreciated thatthe one or more of the storage truck, pipeline, storage tank, gasproducing well, or other suitable gas supply source are interconnect toand in fluid communication with the wellhead 226 and the wellbore 218.Moreover, it can be further appreciated that the wellbore 218 is influid communication with subterranean formation 206.

The gas 216 can be a gas in the gas phase, a gas in the liquid phase, ora combination thereof. In some embodiments, the gas 216 can be in thegas phase. In such embodiments, the gas 216 can be pumped directly intothe wellbore 218 from wellhead 226. In some embodiments, the gas 216 canbe in the liquid phase when introduced at the wellhead 226. In suchembodiments, the liquid phase gas 216 can be directly injected into thewellbore 218 or it can be heated one or more during or after beinginjected into the wellbore 218. It can be appreciated that the liquidphase gas 216 is generally sufficiently heated during or after beinginjected into the wellbore 218 that it is substantially in gas phasewhen it infiltrates the pore volumes and/or fractures of subterraneanformation 206. In some embodiments, when the gas 216 is in a liquidphase when introduced to the well and reservoir 220, the gas 216 can beallowed to remain in the well and reservoir 220 for a sufficient amountof time such that the reservoir temperature causes the liquid phase gas216 to undergo a phase change from a liquid phase to a gas phase beforeand/or substantially simultaneously with infiltration of the fracturesand pore volumes of the subterranean formation 206. For example, thewell and reservoir 220 can have a reservoir temperature from about 120degrees Fahrenheit to about 600 degrees Fahrenheit, or even greater thanabout 600 degrees Fahrenheit. A gas 216 in a liquid phase can have atemperature less than the reservoir temperature. Generally, a gas 216 inthe liquid phase can have a temperature from about −69 degreesFahrenheit to about 80 degrees Fahrenheit. It can be appreciated thatthe higher reservoir temperature of the well and reservoir 220 canprovide sufficient heat to the liquid phase gas 216 to induce a phasetransition from the liquid phase to the gas phase.

Typically, the gas 216 can infiltrate the subterranean formation 206from about 1 to about 7,000 feet from one or more of the wellbore 218 orperforation tunnel. More typically, the gas 216 can infiltrate thesubterranean formation 206 from about 10 to about 5,000 feet from one ormore of the wellbore 218 or perforation tunnel. More typically, the gas216 can infiltrate the subterranean formation 206 from about 100 toabout 3,000 feet from one or more of the wellbore 218 or perforationtunnel. Commonly, the gas 216 can infiltrate the subterranean formation206 no more than about 7,000 feet, more commonly no more than about5,000 feet, or even more commonly no more than about 3,000 feet from oneor more of the wellbore 218 or perforation tunnel. Usually, the gas 216can infiltrate the subterranean formation 206 more than about 1 foot,more usually more than about 10 feet, or even more usually more thanabout 100 feet from one or more of the wellbore 218 or perforationtunnel.

The gas 216 is generally introduced into the well and/or reservoir 220through wellhead 226. In some embodiments of step 200, the flow of thegas 216 can be one or more of monitored and controlled by a controlsystem. The control system can include one or more of (a) pressuresensor(s), gauge(s) and switch(es) arrangement any manner or combinationthereof.

Typically, the injecting of the gas 216 can be in a substantiallyuninterrupted continuous flow until the desired volume of the gas 216has been injected. In some embodiments, the injecting the gas 216 canintermittently, where the flow of the gas 216 can be started and stoppedin succession any number of times until the desired volume of gas 216has been injected.

The gas 216 can be maintained in the well and/or reservoir 220 for adwell period of time. The dwell period of time can comprise little, ifany, time. However, in some embodiments, a dwell period of time existsbetween the halting and the starting of the injection of gas 216. Insome embodiments, the dwell period of time can be long (such as hours ordays) or short (such as minutes or hours). While not wanting to belimited by example, the gas 216 can be injected in the liquid phasewhere a dwell period of time can be needed for the liquid phase toundergo a phase transition to the gas phase. In some embodiments, thedwell period of time can be as short as about 5 minutes or as long asabout 24 hours. In some embodiments, the dwell time can be less than onehour. In some embodiments, the dwell time can be less than thirtyminutes. In other embodiments, the dwell time can be no more than twentyfour hours. In other embodiments, the dwell time can be more than twentyfour hours.

As can be appreciated in some embodiments, the gas 216 can be in theform of a foam. The foam can be injected into the well and reservoir220. Foam quality is conventionally defined as the volume percent gaswithin the foam at a specified pressure and temperature. The volume %value generally refers to the volume % of gas in the foam. The balanceof the volume % of the foam is usually liquid. Typically, the quality ofthe foam injected into the well and reservoir 220 is about 30 volume/0or more. More typically, the quality of foam is about 40 volume % ormore, even more typically 50 volume % or more, yet even more typicallyabout 60 volume/0 or more, still yet even more typically about 70 volume% or more, still yet even more typically about 80 volume % or more, oryet still even more typically about 90 volume % or more. That is, insome embodiments, the quality of the foam can be greater than about 30volume % gas in the foam with the balance being liquid. That is, in someembodiments, the quality of the foam can be greater than about 40 volume% gas in the foam with the balance being liquid. That is, in someembodiments, the quality of the foam can be greater than about 50 volume% gas with the balance being liquid. That is, in some embodiments, thequality of the foam can be greater than about 60 volume % gas in thefoam with the balance being liquid. That is, in some embodiments, thequality of the foam can be greater than about 70 volume % gas in thefoam with the balance being liquid. That is, in some embodiments, thequality of the foam can be greater than about 80 volume % gas in thefoam with the balance being liquid. That is, in some embodiments, thequality of the foam can be greater than about 80 volume % gas in thefoam with the balance being liquid. That is, in some embodiments, thequality of the foam can be greater than about 90 volume % gas in thefoam with the balance being liquid. In accordance with some aspects ofthe present disclosure, the gas can be in the form of a foam. Inaccordance with some embodiments of the present disclosure the foam cancontain more gas by volume than liquid by volume. It can be appreciatedthat in some embodiments the foam can contain less gas by volume thanliquid by volume. Typically, the foam can have no more than about 50volume % liquid, no more than about 45 volume % liquid, no more thanabout 40 volume % liquid, no more than about 35 volume % liquid, no morethan about 30 volume % liquid, no more than about 25 volume % liquid, nomore than about 20 volume % liquid, no more than about 15 volume %liquid, no more than about 10 volume % liquid, no more than about 5volume % liquid, no more than about 2 volume % liquid, no more than 1volume % liquid, or no more than about 0.1 volume %) liquid. Inaccordance with some embodiments, the foam can have at least about 1volume % liquid, at least about 5 volume % liquid, more typically atleast about 10 volume % liquid, or at least about 15 volume % liquid.The percent by volume of the liquid and/or gas is typically measured atthe wellhead 226 prior to the injection of the foam into the wellbore218. Moreover, it can be appreciated that volume % of liquid in foam canvary according to temperature and pressure. Hence, the volume % ofliquid in the foam generally correspond without limitation to thosemeasured at the temperature and pressure of the foam immediately priorto the injection of the foam at the wellhead 226.

The gas 216 may or may not be substantially free of particulates. Theparticles can comprise, a solid, semi-solid, a liquid diverting agent,or any combination thereof. Typically, the gas (as measured at thesurface) has no more than about 5 volume % particulates, more typicallyno more than about 2.5 volume % particulates, more typically no morethan about 1 volume % particulates, more typically no more than about0.75 volume % particulates, more typically no more than about 0.5 volume%) particulates, more typically no more than about 0.25 volume %particulates, and even more typically no more than about 0.1 volume %particulates. Although particulates are beneficial in some applications,particulate diverting agents, in particular, can cause productionproblems downhole. They can one or more of restrain, impair, and damageporosity and permeability. It can be appreciated that the one or more ofrestrained, impaired, and damaged porosity and permeability can impedehydrocarbon flow from the fractures and exposed surfaces in the wellbore218 contacted by any other diverting agent(s). The gas 216 is generallysubstantially free of particles.

It can be further appreciated that the gas 216 can be substantiallycompressible. Typically, the gas 216 is compressed within the wellbore218 and the reservoir. It can be further appreciated that a fracturingliquid 202, which is injected in step 320 following the injection of thegas 216 in step 310. It can be appreciated that the fracturing liquid202 is generally substantially incompressible. Compared with thefracturing liquid 202, the gas 216 more easily fills the fracturesand/or pore volumes of the subterranean formation 206. Ability of thegas 216 to more easily fill the fractures and/or pore volumes ofsubterranean formation 206 than the fracturing liquid 202 can be due oneor more of the following: (a) the higher surface tension of thefracturing liquid 202, compared to the gas 216; (b) the lower density ofthe gas 216 compared to the fracturing liquid 202; (c) the inability ofthe fracturing liquid 202 to wet the subterranean formation 206; and (d)the ability of the gas 216 to diffuse into the subterranean formation206 compared to the impermeability of fracturing liquid 202 tosubterranean formation 206. While not wishing to be bound by any theory,it is believed that the gas 216 (in any of the forms as describedherein) will fill or occupy fractures in the formations along thewellbore 218 (e.g., the first portion fractures and pore volumes 208which is often already fractured and/or has a low pore pressure) and,when contacted with the fracturing liquid 202, will compress until afracture gradient is reached, thereby causing fracture initiation andpropagation in a previously unstimulated zone.

Typically, the one or more of fractures and pore volumes 208 are infirst stress zone 210 of subterranean formation 206. The injected gascan infiltrate and pressurize the subterranean formation 206 and thereservoir holding the hydrocarbons. The gas can travel through a networkof the first portion fractures and pore volumes 208. The first portionfactures and pore volumes 208 can be man-made, naturally occurring or acombination of naturally occurring and man-made. That is, the firstportion factures and/or pore volumes 208 can be preexisting within thenatural formation and/or regions of hydrocarbon depletion. Uponinfiltration, the gas 216 will occupy the first portion fractures andpore volumes 208 in the subterranean formation 206. This gasinfiltration into the first portion factures and pore volumes 208 cancreate a sufficient pressure in the first stress zone 210 and the firstfactures and pore volumes 208 to allow a fracturing liquid 202 tofracture previously unstimulated zones. These previously unstimulatedzones fractured by the fracturing liquid 202 can be portions of thesubterranean formation 206 that are a significant distance from wellbore218 (i.e., far-field) compared any previous stimulated areas. Moreover,these previously unstimulated areas fractured by the fracturing liquid202 can be portions of the subterranean formation 206 previously havinglittle, if any, of one or both hydrocarbon permeability and productionprior to being fractured by the fracturing liquid 202. While not wantingto be limited by theory, it is believed that the infiltration of the gas216 into the first portion factures and pore volumes 208 can create abarrier for the fracturing liquid 202 that is subsequently deliveredinto the wellbore 218 and diverted to the second stress zone 214. Thegas 216 in the stimulation network can build a sufficient pressure inthe network allowing subsequently delivered fracturing liquid 202 to bediverted into previously untreated areas of the subterranean formation206. In some instances, this method will allow for the diversion of thefracturing liquid 202 to a portion of the subterranean formation 206that is a significant distance from the wellbore 218 (i.e. far-field).While not wanting to be limited by theory, it is believed that thefractures generated in the previously unstimulated zones can be in someembodiments the second portion fractures and pore volumes 212. It isalso believed that that the fractures generated in the previouslyunstimulated zones can be in some embodiments new fractures and porevolumes in the first stress zone 210 that are not part of the firstportion fractures and pore volumes 208. Moreover, it is believed that insome embodiments the fractures generated in the previously unstimulatedzones can be a combination of the second portion fractures and porevolumes 212 and the new fractures and pore volumes in the first stresszone 210 that are not part of the first portion fractures and porevolumes 208.

The fracturing liquid 202 can be without limitation one or more ofslick-water, a gel, and a fracturing foam. Commonly, the slick watercomprises a low viscosity water-based fluid. More commonly, the slickwater comprises a low viscosity water-based fluid with a proppant. Thegel can comprise one or more of a borate, hydroxypropyl guar (HPG),carboxymethyl hydroxypropyl guar (CMHPG), and carboxymethyl cellulose(CMC). The fracturing foam can comprise one or more of nitrogen andwater with gel, carbon dioxide, propane, and combinations thereof. Insome embodiments, the fracturing liquid 202 or an amount of water usedin the fracturing liquid 202 can be supplied by storage tanks, naturallyformed features (e.g., spring), a pipeline, etc.

The fracturing liquid 202 can be continuously injected or it can beintermittently injected into the wellbore 218 and reservoir. In the caseof intermittent injection, the injecting of the fracturing liquid 202can be halted for a period of time before continuing with injectingprocess. The period of time between injections can be a period ofminutes, hours, or days. For example, the period of time betweeninjections can be at least about 1 minute, at least about 5 minutes, atleast about 10 minutes, at least about 20 minutes, at least about 30minutes, at least about 45 minutes, at least about 1 hour, at leastabout 2 hours, or at least about 3 hours, among other time periods.

The initial gas 216 injection typically goes into the low stressed poreareas and increases the stress of the pore areas. It is believed thatthe leak-off rate of the injected fracturing liquid 202 into the poresis slowed by the gas 216. Fractures are generally larger than pores.With respect to fractures, the fracturing liquid 202 is not believed toforce the gas 216 out of the fractures in the low stress zones due tothe effects of frictional resistance to multi-phase flow (including bothliquid and gas). When the injection pressure is more than the frictionalresistance, the fracturing liquid 202 is believed to displace the gas216 from the fractures. However, as the fracture decreases in size(e.g., width and/or height) it is believed that the resistance to flowwill increase above the injection pressure, thereby preventing thefracturing liquid 202 from displacing the gas 216 from the fracture.When the fracture gradient is reached, fracture initiation andpropagation commence, such as in the high stress zones. The gas 216 isthus believed to block the fracturing liquid 202 from propagating thefracture in the low stress zone. When injections of gas 216 andfracturing liquid 202 are alternated, it is believed that the gas 216will enter the subterranean formation 206 having the next lowestfracture gradient.

It is further believed that the gas 216 (in any of the forms asdescribed herein) can fill and/or occupy the fractures and pore volumesin the subterranean formation 206 along the wellbore 218. Typically, thegas 216 can fill and/or occupy the factures and pore volumes in one ormore of the first 210 and second 214 stress zones. Moreover, when thegas 216 in the one or more of the first 210 and second 214 stress zonesis contacted with the pressurized fracturing liquid 202, the gas 216 canbe compressed. That is, the gas 216 can be pressurized within the one ormore of the first 210 and second 214 stress zones. While not wanting tobe limited by theory, it is believed that the gas 216 compressed in theone or more of the first stress zones 210 and second stress zones 214can be pressurized until the fracture gradient of one or both of first210 and second 214 stress zones is reached, thereby causing one or morefractures to initiate and propagation within the one or both of thefirst 210 and second 214 stress zones. It is further believed that atleast some, if not most, of the one or more fractures initiated andpropagated by the compressed gas can be in previously unstimulatedzones. Moreover, it is further believed that at least some, if not most,of the one or more fractures initiated and propagated by the compressedgas can occur in portions of the first 210 and/or second 214 stresszones previously unstimulated by a pressured fracturing fluid. In otherwords, the gas 216 can fill, occupy and pressurize the portions off thefirst 210 and/or second 214 stress zones that the previous pressurizedfracturing fluid could not and thereby fracture the previouslyunstimulated portions of the first 210 and/or second 214 stress zones.

It can be further appreciated that the fracturing liquid 202 can orcannot include a diverting agent. The diverting agent can be a chemical,a mechanical device, or a biological material. For example, thediverting agent can be a particulate material. The diverting agent canbe any diverting agent commonly used in diverting systems and any of theothers not commonly used. The particulate materials can be blended withthe fracturing liquid 202 to form the diverting composition and theninjected into the wellbore 218. Examples of diverting agents that can bemixed with the fracturing liquid 202 include, but are not limited to,sand, ceramic proppant, resin coated proppant (ceramic, sand or other),salts, water soluble balls of polyesters/polylactide copolymercompounded with plasticizers, degradable fibers, starches (e.g., cornstarch), gels, guar, ceramic beads, bauxite, glass microspheres,synthetic organic beads, sintered materials and combinations thereof,polymer materials, fluoro-polymer particulates (such as, but not limitedto TEFLON™ fluoro-polymer particulates), nut shell pieces, seed shellpieces, cured resinous particulates comprising nut shell pieces, curedresinous particulates including seed shell pieces, fruit pit pieces,cured resinous particulates including fruit pit pieces, wood, compositeparticulates and any combinations thereof. The diverting agent can bedegradable and can include but not be limited to degradable polymers,dehydrated compounds, and mixtures thereof. Examples of degradablepolymers that can be used as a diverting agent can include, but not belimited to homopolymers, and random, block, graft, and star- orhyper-branched polymers. Examples of suitable polymers includepolysaccharides such as dextran or cellulose, chitin, chitosan,proteins, aliphatic polyesters, poly(lactide), poly(glycolide),poly(ε-caprolactone), poly(hydroxybutyrate), poly(anhydrides), aliphaticpolycarbonates, poly(ortho esters), poly(amino acids), poly(ethyleneoxide), and polyphosphazenes. Polyanhydrides are another type ofsuitable degradable polymer. Examples of suitable polyanhydrides includepoly(adipic anhydride), poly(suberic anhydride), poly(sebacicanhydride), and poly(dodecanedioic anhydride). Other suitable examplesinclude, but are not limited to, poly(maleic anhydride) and poly(benzoicanhydride). These and other diverting agents can be used in theembodiments described herein.

In some embodiments, the fracturing liquid 202 can contain a divertingagent. In such instances, those of skill in the art generally refer tosuch a composition (that is, a composition containing fracturing liquidand a diverting agent), a diverting composition. It can be appreciatedthat step 320 can include injecting the fracturing liquid 202 with orwithout a diverting agent mixed with the fracturing liquid 202 into thewellbore 218 such that the fracturing liquid 202, with or without thediverting agent, pressurizes the subterranean formation 206 andinitiates and propagates one or more fractures in previouslyunstimulated zones of the subterranean formation 206. Without injectingthe gas 216 into the wellbore 218, the fracturing liquid 202, with orwith the diverting agent, would not be diverted to the previouslyunstimulated zones and would otherwise infiltrate the previouslystimulated fractures. In other words, sufficiently pressurizing thepreviously stimulated fractures can cause the subsequently injectedfracturing liquid 202, with or without diverting agent, to bypass thepressurized, gas-filled previously stimulated fractures and infiltratethe previously unstimulated zones of the subterranean formation 206. Itcan be appreciated that the infiltration of the previously unstimulatedzones by the fracturing liquid 202 can fracture at least some of thepreviously unstimulated zones of the subterranean formation 206.

It can be further appreciated that injecting the fracturing liquid 202with or without a diverting agent mixed with the fracturing liquid 202into the wellbore 218 such that the fracturing liquid 202, with orwithout the diverting agent, pressurizes the first portion of thesubterranean formation 206 and initiates and propagates one or morefractures in the second portion of the subterranean formation 206. Inother words, without the injection of the gas 216 into the wellbore 218,the fracturing liquid 202, with or with the diverting agent, would notbe diverted to the second portion of the subterranean formation 206 andwould otherwise infiltrate the first portion of the subterraneanformation 206. Moreover, sufficiently pressurizing the first portion ofthe subterranean can cause the subsequently injected fracturing liquid202, with or without diverting agent, to bypass the pressurized,gas-filled first portion of the subterranean formation 206 andinfiltrate the second portion of the subterranean formation 206. It canbe appreciated that the infiltration of the second portion of thesubterranean formation 206 by the fracturing liquid 202 can fracture atleast some of the second portion of the subterranean formation 206.

Generally, it is believed that injecting the fracturing liquid 202 withor without a diverting agent mixed with the fracturing liquid 202 intothe wellbore 218 such that the fracturing liquid 202, with or withoutthe diverting agent, pressurizes the first stress zone 210 of thesubterranean formation 206 and initiates and propagates one or morefractures in the second stress zone 214 of the subterranean formation206. More generally, the first stress zone 210 has a lower stress thanthe second stress zone 214. Even more generally, the first stress zone210 contains previously stimulated, first portion fractures and poresvolumes 208. In other words, without the injection of the gas 216 intothe wellbore 218, the fracturing liquid 202, with or with the divertingagent, would not be diverted to the second stress zone 214 of thesubterranean formation 206 and would otherwise infiltrate the firstportion fractures and pore volumes 208. Moreover, sufficientlypressurizing the first portion fractures and pore volumes 208 can causethe subsequently injected fracturing liquid 202, with or withoutdiverting agent, to bypass the pressurized, gas-filled first portion ofthe fractures and pore volumes 208 and infiltrate the second stress zoneof the subterranean formation 206. It can be appreciated that theinfiltration of the second stress zone of the subterranean formation 206by the fracturing liquid 202 can fracture at least some of the secondstress zone of the subterranean formation 206.

Moreover, in accordance with some embodiments, it believed that the gas216 can infiltrate and pressurize the fractures and/or pore volumes inone or both of the first and second portions of the subterraneanformation 206 prior to the introduction of the fracturing liquid 202 toone or both of the first and second portions of the subterraneanformation 206. Furthermore, it is believed that the gas 216 caninfiltrate and pressure fractures and/or pore volumes that thefracturing liquid 202 is substantially unable to infiltrate andpressurize. More specifically, it is believed that the gas 216 caninfiltrate and pressure fractures and/or pore volumes that thefracturing liquid 202 is substantially unable to infiltrate andpressurize under the pressure that the fracturing liquid 202 isintroduced into the subterranean formation 206. In other words, the gas216 within the fractures and/or pore volumes of subterranean formation206 is further pressurized by the fracturing liquid 202. This furtherpressurization of the gas 216 within the fractures and/or pore volumesone or both of: (a) forms barrier between fracturing liquid 202 and thegas filled factures and pore volumes and (b) achieves a sufficientpressure within the gas filled fractures and pore volumes to fractureone or more of the gas filled fractures and/or pore volumes. It can beappreciated that the fractures that develop in the one or more of thegas filled fractures and/or pore volumes can be in one or more of thefirst 210 and second 214 stress zones are new fractures and were notprevious manmade and/or naturally occurring fractures. Typically, thesecond stress zone 214 has a greater stress than the first stress zone210. In some embodiments, the first stress zone 210 has a greater stressthan the second stress zone 214.

In accordance with some embodiments, the injecting of the gas 216 ismaintained for a period of time. It can be appreciated that period ofinjecting the gas 216 generally refers to the period starting with theinjection of the gas 216 and ending with the starting of the injectingof the fracturing liquid 202. Typically, the period of injecting the gas216 is about 0.1 hours or more. More typically, the period of injectingthe gas is about 0.2 hours or more, even more typically about 0.3 hoursor more, yet even more typically about 0.4 hours or more, still yet evenmore typically about 0.5 hours or more, still yet even more typicallyabout 0.6 hours or more, still yet even more typically about 0.7 hoursor more, still yet even more typically about 0.8 hours or more, stillyet even more typically about 0.9 hours or more, still yet even moretypically about 1.0 hour or more, still yet even more typically about1.5 hours or more, and yet still even more typically at least about 2.0hours or more. In accordance with some embodiments, the period ofinjecting the gas 216 can commonly be no more than about 30 days, evenmore commonly no more than about 25 days, even more commonly no morethan about 20 days, yet even more commonly no more than about 19 days,still yet even more commonly no more than about 18 days, still yet evenmore commonly no more than about 17 days, still yet even more commonlyno more than about 16 days, still yet even more commonly no more thanabout 15 days, still yet even more commonly no more than about 14 days,still yet even more commonly no more than about 13 days, still yet evenmore commonly no more than about 12 days, still yet even more commonlyno more than about 11 days, and yet sill even more commonly no more thanabout 10 days.

In some embodiments, the gas 216 can be injected into the wellbore 218over an extended period of time. For example, the gas 216 can beinjected over a period of time that can be minutes, hours, days, ormonths, depending on a number of factors. In some embodiments, the gas216 can be injected over a period of time of more than about 2 hrs. Inother embodiments, the gas 216 can be injected over a period of time ofmore than a day. For example, in some embodiments, the gas 216 can beinjected into the wellbore 218 from a neighboring natural gas well. Thepressure at wellbore 218 can be checked during and/or any time periodafter the injection of the gas 216 to determine if the pressure issufficient for the introduction of the fracturing liquid 202. If thepressure is not sufficient, additional gas 216 needs to be injected intothe wellbore 218 directly or through the neighboring natural gas well.It can be appreciated that it is possible for weeks to go by withintermittent addition of gas 216 into the wellbore 218 before asufficient pressure is reached to begin introduction of the fracturingliquid 202.

Furthermore, it is believed that sufficiently pressurizing the first 210and second 214 portions of the subterranean formation 206 with the gas216 prior to the injecting of the fracturing liquid 202, with or withoutthe diverting agent, causes the injected fracturing liquid 202 to one ormore of permeate, fill, occupy, and pressurize one or more of thefractures and pore volumes of previously unstimulated and/or understimulated zones. In particular, sufficiently pressurizing the first 210and second 214 portions of the subterranean formation 206 with gas 216prior to the injecting and the fracturing liquid 202, with or without adiverting agent, causes the injected fracturing liquid 202 to one ormore of permeate, fill, occupy, and pressurize one or more of thefractures and pore volumes of previously unstimulated and/or understimulated zones of one or more of the first 210 and second 214 portionsof the subterranean formation 206.

In some embodiments, step 320 can include introducing the fracturingliquid 202, with or without a diverting agent, into the wellbore 218 andreservoir 220 after step 310 to pressurize the subterranean formation206. The pressurization of the subterranean formation 206 by thefracturing liquid 202 is sufficient to fracture a portion of thesubterranean formation 206. It can be appreciated the introduction ofthe fracturing liquid 202 into the subterranean formation 206 canpressurize one or more of the first and second portions of thesubterranean formation 206. It can be further appreciated thatintroduction of the fracturing liquid 202 into the subterraneanformation can pressurize one or both of the first stress zone 210 andthe second stress zone 214. Generally, the second stress zone 214 has ahigher stress than the first stress zone 210. Typically, one of first210 and second 214 stress is pressurized more than the other. In someembodiments, the first stress zone 210 is pressurized more than thesecond stress zone 214. In some embodiments, the second stress zone 214is pressurized more than the first stress zone 210. Typically, thefracturing liquid 202 pressurizes the second stress zone 214 more thanthe first stress zones 210, thereby fracturing the second stress zone214 to a greater extent than the first stress zone 210. While notwanting to be limited by theory, it is believed that one or both of thegas 216 and diverting agent (when the fracturing liquid 202 contains adiverting agent) substantially impedes and/or diverts pressurization ofthe first stress zone 210 by the fracturing liquid 202 to substantiallyfracture first stress zones 210. However, the fracturing liquid 202 cantypically sufficiently pressurize the second stress zone 214 tosubstantially fracture the second stress zone 214. Moreover, the secondfractures and pore volumes 212 are usually formed in the second stresszone 214 by the pressurized fracturing liquid 202.

The fracturing liquid 202 can be injected into the well and/or reservoir220. Step 320 can include injecting the fracturing liquid 202 into thewell and/or reservoir 220 through wellhead 226. In some embodiments,step 320 can include the sub-steps of starting and halting of theinjecting of the fracturing liquid 202 into the well and/or reservoir220. Step 320 can also include the sub-step of providing the fracturingliquid 202. Typically, the fracturing liquid 202 can be provided by oneor more of a storage truck, a storage tank or other supply source. Insome embodiments, step 320 can include injecting the fracturing liquid202 at an injection rate. Commonly, the injection rate of the fracturingliquid 202 can be from about 2 barrels/minute (bbl/min.) (about 84gallons/min.) to about 200 bbl/min. (about 8,400 gallons/min). Morecommonly, the injection rate of the fracturing liquid 202 can be morethan about 200 bbl/min (more than about 8,400 gallons/min).

It can be appreciated that in some embodiments, a first portion of thefracturing liquid 202 can contain a diverting agent and a second portionof the fracturing liquid 202 can be substantially devoid of anydiverting agent. While not wanting to be limited by example, a firstportion of the fracturing liquid 202 containing a diverting agent can beinjected into the wellbore and reservoir 220 before a second portion ofthe fracturing liquid 202 substantially devoid of any diverting agent.It can be appreciated that the introduction of the first portion of thefracturing liquid 202 containing a diverting agent into the subterraneanformation 206 can occupy one or more of the first and second portions ofthe subterranean formation 206. While not wanting to be limited bytheory, it is believed that the first portion of the fracturing liquid202 fracturing liquid containing the diverting agent occupies the firstportion of the subterranean formation 206. It is further believed thatthe first portion of the fracturing liquid 202 containing the divertingagent occupying the fractures and pore volumes of the first portion ofthe subterranean formation 206 substantially impedes and/or diverts thesecond portion of the fracturing liquid 202 devoid of a diverting agentfrom first portion of subterranean formation 206 to the second portionof subterranean formation 206. Hence, it is believed that the secondportion of the fracturing liquid 202 devoid of the diverting agent cantherefore pressurize the second portion of subterranean formation 206 toa sufficient pressure to fracture some of the second portion of thesubterranean formation 206. It can be further appreciated that in someembodiments the introduction of the first portion of the fracturingliquid 202 containing a diverting agent into the subterranean formation206 can occupy one or more of the first stress zone 210 and secondstress zone 214. While not wanting to be limited by theory, it isbelieved that the first portion of the fracturing liquid 202 fracturingliquid containing the diverting agent occupies the first stress zone210. It is further believed that the first portion of the fracturingliquid 202 containing the diverting agent occupying the fractures andpore volumes of the first stress zone 210 substantially impedes and/ordiverts the second portion of the fracturing liquid 202 devoid of adiverting agent from the first stress zone 210 to the second stress zone214. Hence, it is believed that the second portion of the fracturingliquid 202 devoid of the diverting agent can therefore pressurize thesecond stress zone 214 to a sufficient pressure to fracture some of thesecond stress zone 214.

In some embodiments, the diverting agent can one or more of block andpressurize the first portion of subterranean formation 206 such that thefracturing liquid 202 can bypass the gas-filled and/or diverting agentfilled first portion of the subterranean formation 206. Thus, thefracturing liquid 202 can infiltrate and fracture the second portion ofthe subterranean formation 206. Consequently, when the diverting agentis combined with the fracturing liquid 202, two different divertingtechniques (e.g., gas and the diverting agent) are utilized to divertthe fracturing liquid 202 to the second portion of the subterraneanformation 206 and fracture the second portion of the subterraneanformation 206. It can be appreciated that in some embodiments the firstportion of the subterranean formation 206 can comprise a first stresszone 210. Furthermore, the second portion of the subterranean formation206 can comprise a second stress zone 214. Generally, the first stresszone 210 has a lower stress than the second stress zone 214. Moreover,the first stress zone 210 contains first fractures and a pore volumes208. Furthermore, the fractures formed in the second stress zone 214 cancomprise the fractures and pore volumes 212.

In accordance with some embodiments, the gas 216 can infiltrate thesubterranean formation 206 beyond the wellbore 218 to a distance that issubstantially far-field from the wellbore 218. More specifically, thegas 216 can infiltrate the fractures and/or pore volumes of thesubterranean formation 206 beyond the wellbore 218 to a distance that issubstantial or far-field from the wellbore 218. Furthermore, the gas 216can infiltrate the subterranean formation 206 outside of a perforationtunnel, or outside of a formation face in open hole. Typically, the gas216 can infiltrate the fractures and/or pore volumes extendingthroughout the reservoir 220, including far-field areas along less thanhalf of the entire length of the wellbore 218. More typically, the gas216 can infiltrate the fractures and/or pore volumes extendingthroughout the reservoir 220, including far-field areas along more thanhalf of the entire length of the wellbore 218. Even more typically, thegas 216 can infiltrate the fractures and/or pore volumes extendingthroughout the reservoir 220, including far-field areas along the entirelength of the wellbore 218. This is at least one advantage ofinfiltrating the gas 216 with the subterranean formation 206 compared totypical chemical and particulate diverter systems.

It accordance with some embodiments, steps 310 and 320 can repeated anynumber of times. Moreover, in some embodiments, one or more of thesub-steps of step 320 can be repeated in any order and any number oftimes within step 320. While not wanting to be limited by example, steps310 and 320 can be repeated one of 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, or 12times. Moreover, steps 310 and 320 can be repeated sequentially oneafter the other in any order. In accordance with some embodiments, whenstep 310 is repeated the gas 216 can be: in some, or all, of steps 310in the gaseous phase; in some, or all, of steps 310 in the liquid phase;in some, or all, of steps 310 in the form of foam; or a combination ormixture thereof. In some embodiments, step 310 is conducted sequentiallyany number of times before step 320. While not wanting to be limited byexample, step 310 can be conducted one of 1, 2, 3, 4, 5, 6, 7, 8, 9 10,11, or 12 times before conducting step 320. In some embodiments, step320 is conducted sequentially any number of time after step 310. Whilenot wanting to be limited by example, step 320 can be conducted one of1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, or 12 times after conducting step310. It can be appreciated that step 320 can include the recitation ofany of the sub-steps of 320. Any of the sub-steps of 320 can be repeatedone of 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, or 12 times when conducting aniteration of step 320.

In some embodiments, steps 310 and 320 can be conducted concurrentlyand/or at about the same time. Step 320 may be conducted with adiverting agent, without a diverting agent, or with combination offracturing liquids with and without diverting agents. In someembodiments, steps 310 and 320 are conducted simultaneously without anyprevious injection of gas 216 into the well 220.

In accordance with some embodiments, one of step 320 with a compositioncontaining a diverting agent or step 310 is conducted prior to injectinga fracturing liquid devoid of a diverting agent. It can be appreciatedthat any one of the steps 320 with a composition containing a divertingagent and 310 can be repeated any number of times before the injectingof the fracturing liquid devoid of any diverting agent.

In accordance with some embodiments, one of step 320 with a compositioncontaining a diverting agent or step 310 follows the injecting afracturing liquid devoid of a diverting agent. It can be appreciatedthat any one of the steps 320 with a composition containing a divertingagent and 310 can be repeated any number of times following theinjecting of the fracturing liquid devoid of any diverting agent.

While not wanting to be limited by example, the methods disclosed hereincan include: a first diverting composition is injected; a seconddiverting composition is injected; and the fracturing liquid isinjected. Another example order of injections into the well andreservoir can be as follows: a first diverting composition is injected;the fracturing liquid is injected; a second diverting composition isinjected. In each of these examples, the first and second divertingcompositions can be the gas or foam 216 or the diverting compositionincluding a diverting agent mixed with the fracturing liquid 202.Consequently, and more specifically, the examples above can be asfollows: a gas or foam is injected; a diverting composition includingthe diverting agent mixed with a fracturing liquid is injected; thefracturing liquid is injected. The second example may, morespecifically, be as follows: a gas or foam is injected; the fracturingliquid is injected; a diverting composition including the divertingagent mixed with a fracturing liquid is injected. These are merelyexamples and other sequences are possible and contemplated herein.

The entire cycle of steps 310 and 320 repeated if the well and/orreservoir 220 require additional treatment, for example, to divert theflow of fracturing liquid 202 from one of the first and second portionsof the subterranean formation 206 to the other of the first and secondportions of the subterranean formation 206. Moreover, the flow offracturing liquid 202 from one of the first and second portions of thesubterranean formation 206 to the other of the first and second portionsof the subterranean formation 206 for additional fracturing of the oneof the first and second portions of the subterranean formation 206 thatwere formed from the previous operations to fracturing of previouslyunstimulated and/or under stimulated zones of the other of the first andsecond portions of subterranean formation 206.

Typically, the entire cycle of steps 310 and 320 repeated if the welland/or reservoir 220 require additional treatment, for example, todivert the flow of fracturing liquid 202 from the first portion of thesubterranean formation 206 to the second portion of the subterraneanformation 206 for fracturing. Furthermore, the flow of fracturing liquid202 from the first portion of the subterranean formation 206 to thesecond portion of the subterranean formation 206 for additionalfracturing of the first portion of the subterranean formation 206 thatwere formed from the previous operations to fracturing of previouslyunstimulated and/or under stimulated zones of the second portion ofsubterranean formation 206.

More typically, the entire cycle of steps 310 and 320 repeated if thewell and/or reservoir 220 require additional treatment, for example, todivert the flow of fracturing liquid 202 from the first stress zone 210of the subterranean formation 206 to the second stress zone 214 of thesubterranean formation 206 for fracturing. Furthermore, the flow offracturing liquid 202 from the first stress zone 210 of the subterraneanformation 206 to the second stress zone 214 of the subterraneanformation 206 for additional fracturing of the first stress zone 210 ofthe subterranean formation 206 that were formed from the previousoperations to fracturing of previously unstimulated and/or understimulated zones of the second stress zone 214 of subterranean formation206.

Typically, the criteria indicating the need for cycling of steps 310 and320 can be if the fracturing liquid 202 experiences a high pressure,which may indicate the presence of a zone that can potentially fracture.On the other hand, lower pressure in the well and/or reservoir 220 canindicate the fracturing liquid 202 is infiltrating previously fracturedand/or hydrocarbon depleted zones.

In step 330, the well is put in production. Step 330 can include thesub-step of back-flushing the fracturing liquid 202 and gas 216. It canbe appreciated that the fracturing liquid 202 and the gas can beback-flushed from the well and/or reservoir 220.

In accordance with some embodiments of this disclosure, the methodsand/or processes can energize the reservoir allowing more effectiveflowback. Moreover, the methods and/or process can allow for higherfluid recovery. Furthermore, the methods and/or process can produce lessclay swelling with the subterranean formation.

In accordance with some embodiments of this disclosure, the methodsand/or processes can allow for fracturing and/or re-fracturing along theentire of the wellbore. Furthermore, the methods and/or processes canallow for fracturing and/or re-fracturing of the toe region of thewellbore. Moreover, the methods as described herein can be used tostimulate or treat vertical, deviated, or horizontal wells. Furthermore,the methods and/or process of this disclosure can be applied to wellscompleted with older techniques. In accordance with some embodiments,the methods and/or processes can create a more complex fracture networkthan methods and/or process of the prior art. In some embodiments ofthis disclosure, the methods and/or process can have the gas injected inthe wellbore does not leave behind any residue within the wellboreand/or subterranean formation.

Aspects of the presently disclosed technology involve a diversiontechnique for use in vertical, deviated, or horizontal wells undergoinga stimulation process (e.g., initial stimulation or re-stimulation) todivert a carrier liquid from treating previously stimulated areas (i.e.,lower stress zones of the formation) and to force the carrier liquid totreat previously unstimulated areas (i.e., higher stress zones of theformation). The methods disclosed provide cost-effective means forimproving the well production. After a wellbore is drilled andcompleted, stimulation operations are usually performed to enhancehydrocarbon (e.g. gas, oil, etc.) production into the wellbore and toenhance extraction of the hydrocarbons from the subterranean formation.

Current diversion techniques use liquid or solid forms, such as chemicalsolutions (e.g., a borate solution) or, particulates (e.g., polymersspheres). The methods of the present disclosure are cost effective,operationally feasible based on current equipment available to theindustry, and can enhance the rate of extraction of the hydrocarbons. Inparticular, the use of a gas (or foam) as the diversion medium allowsfor greater filling of the reservoir in lower stress zones such that acarrier liquid can be more efficiently diverted to the higher stresszones of the reservoir. The use of a gas (or foam) as the diversionmedium also has advantages in that the gas (or gas component of thefoam) can be recovered during flowback. In certain instances, the gas(or gas component of the foam) may be recovered during flowback can bereused, recycled, or marketed.

The gas can be in the form of a foam. While the foam can have moreliquid (e.g., water) than gas by volume, the foam typically can have nomore than about 50 vol. % liquid, no more than about 45 vol. % liquid,no more than about 40 vol. % liquid, no more than about 35 vol. %liquid, no more than about 30 vol. % liquid, no more than about 25 vol.% liquid, no more than about 20 vol. % liquid, no more than about 15vol. % liquid, no more than about 10 vol. % liquid, or no more thanabout 5 vol. % liquid. The foam can have at least about 1 vol. %,liquid, at least about 5 vol. % liquid, more typically at least about 10vol. % liquid, or at least about 15 vol. % liquid. The percent by volumeis typically measured at the well head and prior to injection of thefoam into the well bore.

Additional methods described herein include stimulating a well andreservoir by alternating or simultaneously introducing a gas diverterand a conventional diverter or isolation device (e.g., chemical,biological, or mechanical diverter systems known and unknown (includingbut not limited to Sergifrac™ and packers). In certain instances, usinga conventional diverter along with the gas diverter, described herein,could produce better economic results than either one could produce ontheir own.

More particularly, and as seen in FIG. 4, which is a side view of ahorizontal drilling operation 400 utilizing the diversion techniquedescribed herein, a first step in the diversion technique includesinjecting a gas (or foam) 416 into a wellbore 418 of a well 420 topressurize the fractures 408 in the lower stress zones 410 of thesubterranean formation 406 and the reservoir. In certainimplementations, the gas 416 may be in a liquid, phase, a gas phase, ora foam mixture of gas and a liquid. The gas (or foam) is introduced toinfiltrate the formation 406 and the reservoir holding the hydrocarbons.The gas (or gas component of the foam) can travel through a stimulationnetwork of fractures and/or pore volumes (i.e., man-made or naturallyoccurring). Upon infiltration, the gas (or gas component of the foam)will occupy pore volumes and existing fractures in the formation 406. Insome instances, the pore volume can be preexisting from the naturalformation or areas/regions of hydrocarbon depletion. This gasinfiltration creates a barrier for a carrier liquid 102 that issubsequently delivered into the wellbore and diverted to the higherstress zones 414. The gas in the stimulation network can build asufficient pressure in the network allowing subsequently deliveredcarrier fluid or liquid to be diverted into previously untreated areasof the formation. In some instances, this method will allow for thediversion of a fluid or liquid to a portion of the formation that is asignificant distance from the wellbore (i.e. far-field).

The subterranean formation may include one or more of any type of rocks,such as sedimentary rocks like sandstone, limestone, and shale; igneousrocks like granite and andesite; or metamorphic rocks like gneiss,slate, marble, schist, and quartzite. In certain implementations, thesubterranean formation may be a shale formation, a clay formation, asandstone formation, a limestone formation, a carbonate formation, agranite formation, a marble formation, a coal bed, or combinationsthereof.

While not wishing to be bound by any theory, it is believed that the gas416 (or gas component of the foam) will fill or occupy fractures in theformations along the well bore (e.g., the low stress area which is oftenalready fractured and/or has a lower pore pressure) and, when contactedwith the carrier fluid, will compress until a fracture gradient of oneor more formations is reached, thereby causing fracture initiation andpropagation in the high stress area. The carrier fluid is not believedto force the gas (or gas component of the foam) out of the fractures inthe low stress area due to the effects of frictional resistance toliquid flow. It is believed that the exposed formation surfaces willfrictionally resist the flow of the carrier fluid. When the injectionpressure is more than the frictional resistance, the carrier fluid isbelieved to displace the gas from the fractures. However, as thefracture decreases in size (e.g., width and/or height) it is believedthat the resistance to flow will increase above the injection pressure,thereby preventing the carrier fluid from displacing the gas (or gascomponent of the foam) from the fracture. When the fracture gradient isreached, fracture initiation and propagation commence, such as in thehigh stress area. The gas is thus believed to block the carrier fluidfrom propagating the fracture in the low stress area. When injections ofgas (or foam) and carrier fluid are alternated, it is believed that thegas (or gas component of the foam) will enter the formation having thenext lowest fracture gradient.

As seen in FIG. 5, which is a side view of the horizontal drillingoperation 500 utilizing the diversion techniques described herein, asecond step in the diversion technique includes injecting the carrierliquid 102, or a diverting composition of a diverting agent mixed withthe carrier liquid 102, into the wellbore 518 such that the carrierliquid 102 or diverting composition pressurizes and fractures additionalfractures 512 of the formation 506 that were previously not stimulated.Without injecting the gas (or foam) 416 into the wellbore, the carrierliquid 102 or diverting composition would not be diverted to untreatedareas and would otherwise infiltrate the fractures 508 of the lowerstress zone 510. Sufficiently pressurizing the fractures 508 in thelower stress zone 510 causes the subsequently injected carrier liquid102 or diverting composition to bypass the gas-filled, pressurizedfractures 508 in the lower stress zones 510 and can be directed toinfiltrating the fractures 512 of the high stress zone 514 or create newfractures.

The gas (or foam) can be substantially free of particulates or othersolid, semi-solid, or liquid diverting agents. Typically, the gas (orfoam) (as measured at the surface) has no more than about 5 vol. %particulates (or other diverting agents), more typically no more thanabout 2.5 vol. % particulates (or other diverting agents), moretypically no more than about 1 vol. % particulates (or other divertingagents), more typically no more than about 0.75 vol. % particulates (orother diverting agents), more typically no more than about 0.5 vol. %particulates (or other diverting agents), more typically no more thanabout 0.25 vol. % particulates (or other diverting agents), and evenmore typically no more than about 0.1 vol. % particulates (or otherdiverting agents). Although particulate or other diverting agents arebeneficial in some applications, particulate (or solid) divertingagents, in particular, can cause production problems down hole. They canrestrain porosity and permeability and therefore hydrocarbon flow fromthe fractures and exposed surfaces in the well bore contacted by thediverting agent(s).

As mentioned above and in certain instances, a diverting agent may bemixed with the carrier liquid 102 to form a diverting composition. Thatis, the diverting composition of a diverting agent and a carrier liquid102 may be used to further stimulate the well and reservoir because thediverting agent may block or pressurize fractures 508 in the lowerstress zone 510 such that the carrier liquid 102 bypasses the gas-filledand/or diverter agent filled fractures 508 and, thus, infiltrates thefractures 512 of the high stress zone 514. Consequently, when adiverting composition of a diverting agent is combined with the carrierliquid or fluid 102, two different diverting techniques (e.g., gas andthe diverting composition) are utilized to more effectively divert thecarrier liquid 102 to the fractures 512 in the high stress zone 514.

The diverting agent of the diverting composition may be chemical,mechanical, or biological in nature. For example, the diverting agentmay include particulate materials that are commonly used in divertingsystems and others not commonly used. The particulate materials may beblended with the carrier liquid 102 to form the diverting compositionand then injected into the well. Examples of diverting agents that maybe mixed with the carrier liquid 102 include, but are not limited to,sand, ceramic proppant, resin coated proppant (ceramic, sand or other),salts, water soluble balls of polyesters/polylactide copolymercompounded with plasticizers, degradable fibers, starches (e.g., cornstarch), gels, guar, ceramic beads, bauxite, glass microspheres,synthetic organic beads, sintered materials and combinations thereof,polymer materials, TEFLON™ particulates, nut shell pieces, seed shellpieces, cured resinous particulates comprising nut shell pieces, curedresinous particulates including seed shell pieces, fruit pit pieces,cured resinous particulates including fruit pit pieces, wood, compositeparticulates and any combinations thereof.

The diverting agents may be degradable and may include but are notlimited to degradable polymers, dehydrated compounds, and mixturesthereof. Examples of degradable polymers that may be used include, butare not limited to, homopolymers, and random, block, graft, and star- orhyper-branched polymers. Examples of suitable polymers includepolysaccharides such as dextran or cellulose, chitin, chitosan,proteins, aliphatic polyesters, poly(lactide), poly(glycolide),poly(ε-caprolactone), poly(hydroxybutyrate), poly(anhydrides), aliphaticpolycarbonates, poly(ortho esters), poly(amino acids), poly(ethyleneoxide), and polyphosphazenes. Polyanhydrides are another type ofsuitable degradable polymer. Examples of suitable polyanhydrides includepoly(adipic anhydride), poly(suberic anhydride), poly(sebacicanhydride), and poly(dodecanedioic anhydride). Other suitable examplesinclude, but are not limited to, poly(maleic anhydride) and poly(benzoicanhydride). These and other diverters may be used in the methodsdescribed herein.

Still referring to FIG. 5, both the diverting composition including adiverting agent mixed with the carrier fluid 102 and the carrier fluid102 by itself may be injected into the well and reservoir. In certainembodiments, the diverting composition including the diverting agentmixed with the carrier fluid 102 may be initially introduced into thewell and reservoir, followed by the introduction of the carrier fluid102, by itself, into the well and reservoir to pressurize the fracturesand pores. In certain embodiments, the carrier fluid 102, by itself, maybe initially introduced into the well and reservoir, followed by theintroduction of the diverting composition including a diverting agentmixed with the carrier fluid 102.

When the carrier fluid 102, by itself, is injected into the well andreservoir, the fluid may be continuously injected, or the fluid may beintermittently injected in a hesitation-type manner. In the case ofintermittent injection of the carrier fluid 102, the injection of thefluid may be halted for a period of time and then re-injected. Theperiod of time may be a period of minutes, hours, or days. For example,the period of time may be at least about 1 minute, at least about 5minutes, at least about 10 minutes, at least about 20 minutes, at leastabout 30 minutes, 45 minutes, 1 hour, 2 hours, or three hours, amongother time periods.

Turning back to FIG. 4, the gas 416 (or foam) may be delivered through awellhead 426 of the well 420. In some embodiments, the gas 416 (or foam)may be delivered via a storage truck 422 positioned on the ground 424near the wellhead 426. In other embodiments, the gas 416 (or foam) maybe delivered via pipeline, a storage tank, other gas producing wells, orother suitable supply sources.

The injection pressure of the gas 416 (or foam) depends on the fracturegradient of the low stress area. As will be appreciated, the fracturegradient is the hydrostatic value, typically expressed in psi/ft, thatis required to initiate a fracture in a subsurface formation (geologicstrata). It can be a function of many factors including overburdenstress, Poisson's ratio of the formation (rock), pore pressure gradient,formation (rock) matrix stress coefficient, and matrix stress. There aremany techniques for determining fracture gradient of a formation, suchas the pseudo-overburden stress method, effective stress method,leak-off tests, Hubbert & Willis technique, Matthews & Kelly technique,and Ben Eaton technique. Typically, the gas 416 (or foam) is injectedinto the well bore at a pressure that is less than the fracturegradient(s) of the low and/or high stress areas (and/or other subsurfaceformations along the well bore) to inhibit (further) fracturing of oneor more of these areas. The injection pressure of the gas 416 (or foam)is generally maintained below the fracture gradient of one or more (orall) of these areas during substantially (e.g., typically at least about50%, more typically at least about 75%, more typically at least about90%, and more typically at least about 95% of) the entire duration ofgas 416 (or foam) injection.

Factors effecting the volume of gas 416 (or foam) to be introduced inthe well 420 include the size of the depleted regions of the reservoir(including pore volume and fractures), leak off rate of the gas 416, andthe extent of existing fracture and reservoir conditions (e.g. reservoirpressure—if the pressure is high it will compress the gas or foamrequiring more volume to occupy the fractures/pore volumes).

For instance, in some embodiments, the volume of the gas (or foam) canrange from about 1000 standard cubic feet (scf) to about 100,000,000 scfor greater. In various embodiments, the gas (or foam) can be injected atrates within a range of about 30 scf/min to about 500,000 scf/min. Insome embodiments, the gas (or foam) can be injected at a rate of about10,000 to about 20,000 scf/min.

In some embodiments, the volume of gas (or foam) (as measured at thesurface) is typically at least about 50,000 scf, more typically at leastabout 100,000 scf, more typically at least about 150,000 scf, moretypically at least about 200,000 scf, more typically at least about250,000 scf, more typically at least about 300,000 scf, more typicallyat least about 350,000 scf, more typically at least about 400,000 scf,more typically at least about 450,000 scf, more typically at least about550,000 scf, more typically at least about 600,000 scf, more typicallyat least about 650,000 scf, more typically at least about 700,000 scf,more typically at least about 750,000 scf, more typically at least about800,000 scf, more typically at least about 850,000 scf, more typicallyat least about 900,000 scf, more typically at least about 950,000 scf,more typically at least about 1,000,000 scf, more typically at leastabout 2,000,000 scf, more typically at least about 3,000,000 scf, moretypically at least about 4,000,000 scf, more typically at least about5,000,000 scf, more typically at least about 6,000,000 scf, moretypically at least about 7,000,000 scf, more typically at least about8,000,000 scf, more typically at least about 9,000,000 scf, and moretypically at least about 10,000,000 scf. The volume of gas (or foam) istypically no more than about 500,000,000 scf, more typically no morethan about 400,000,000 scf, more typically no more than about300,000,000 scf, more typically no more than about 200,000,000 scf, moretypically no more than about 100,000,000 scf, and more typically no morethan about 90,000,000 scf.

Stated another way, the volume of gas (or foam) (as measured at thesurface) per linear foot of net reservoir contact area (by the wellbore) (“lfcA”) is typically at least about 500 scf/lfcA, more typicallyat least about 525 scf/lfcA, more typically at least about 550 scf/lfcA,more typically at least about 575 scf/lfcA, more typically at leastabout 600 scf/lfcA, more typically at least about 625 scf/lfcA, moretypically at least about 650 scf/lfcA, more typically at least about 675scf/lfcA, more typically at least about 700 scf/lfcA, more typically atleast about 725 scf/lfcA, and more typically at least about 750scf/lfcA—The volume of gas (or foam) (as measured at the surface) perlinear foot of net reservoir contact area (by the well bore) (“lfcA”) istypically no more than about 5,000 scf/lfcA, more typically no more thanabout 4,750 scf/lfcA, more typically no more than about 4,500 scf/lfcA,more typically no more than about 4,250 scf/lfcA, more typically no morethan about 4,000 scf/lfcA, more typically no more than about 3,750scf/lfcA, more typically no more than about 3,500 scf/lfcA, moretypically no more than about 3,250 scf/lfcA, more typically no more thanabout 3,000 scf/lfcA, more typically no more than about 2,900 scf/lfcA,more typically no more than about 2,800 scf/lfcA, more typically no morethan about 2,700 scf/lfcA, more typically no more than about 2,600scf/lfcA, and more typically no more than about 2,500 scf/lfcA.

The injection rate of the gas (or foam) (as measured at the surface) istypically at least about 30 scf/min, more typically at least about 50scf/min, more typically at least about 100 scf/min, more typically atleast about 200 scf/min, more typically at least about 300 scf/min, moretypically at least about 400 scf/min, more typically at least about 500scf/min, more typically at least about 600 scf/min, more typically atleast about 700 scf/min, more typically at least about 800 scf/min, moretypically at least about 900 scf/min, and more typically at least about1,000 scf/min. The injection rate of the gas (or foam) (as measured atthe surface) is typically no more than about 500,000 scf/min, moretypically no more than about 450,000 scf/min, more typically no morethan about 400,000 scf/min, more typically no more than about 350,000scf/min, more typically no more than about 300,000 scf/min, moretypically no more than about 250,000 scf/min, more typically no morethan about 200,000 scf/min, more typically no more than about 150,000scf/min, and more typically no more than about 100,000 scf/min.

The duration of injection of the gas (or foam) (as measured immediatelybefore or at the start of injection of the carrier fluid) is typicallyat least about 0.1 hours, more typically at least about 0.2 hours, moretypically at least about 0.3 hours, more typically at least about 0.4hours, more typically at least about 0.5 hours, more typically at leastabout 0.6 hours, more typically at least about 0.7 hours, more typicallyat least about 0.8 hours, more typically at least about 0.9 hours, moretypically at least about 1.0 hours, more typically at least about 1.5hours, and even more typically at least about 2.0 hours. The duration ofinjection of the gas (or foam) (as measured immediately before or at thestart of injection of the carrier fluid) is typically no more than about30 days, more typically no more than about 25 days, more typically nomore than about 20 days, more typically no more than about 19 days, moretypically no more than about 18 days, more typically no more than about17 days, more typically no more than about 16 days, more typically nomore than about 15 days, more typically no more than about 14 days, moretypically no more than about 13 days, more typically no more than about12 days, more typically no more than about 11 days, and even moretypically no more than about 10 days.

In certain instances, the gas 416 may be injected into the well over anextended period of time. For example, the gas 416 may be injected over aperiod of time that can be minutes, hours, days, or months, depending ona number of factors. In some embodiments, the gas 416 may be injectedover a period of time of at least 2 hrs. In other embodiments, the gas416 may be injected over a period of time of at least a day. Forexample, in certain instances, the gas 416 may be injected into the wellfrom a neighboring natural gas well, for example. A worker may check thepressure at a subsequent time (e.g., days later) and determine that, inorder to meet a desired pressure within the wellbore, additional gas 416may need to be injected into the wellbore and continue the injection ofthe gas. A subsequent check of the pressure (e.g., days later), mayindicate that the pressure is sufficient for the introduction of thecarrier liquid 102. Thus, in this example, it is possible for weeks togo by with intermittent addition of gas 416 into the well before asufficient pressure is reached to begin introduction of the carrierliquid 102.

The gas 416 may include any number of gasses and may include nitrogen,hydrogen, methane, ethane, propane, butane, carbon dioxide, any inertgas, or any combinations thereof. The gas 416 may be deployed into thewell 420 in a number of ways and in various phases. In certainimplementations, the gas 416 may be in a gas phase and pumped directlyinto the wellbore 418 from the wellhead 426. In other implementations,the gas 416 may be in a liquid phase above ground 424, and the gas 416is heated sufficiently at the surface for the gas 416 to enter the gasphase as it is being introduced into the wellbore 418, thereby being inthe gas phase when it infiltrates the pore volumes and/or fractures.Liquid carbon dioxide and nitrogen are examples of fluids in the liquidphase at the surface and gas phase down hole. In yet otherimplementations, the gas may be in a liquid phase when it is introducedto the wellbore. The gas in the liquid phase may be pumped into the welland allowed to remain in the well 420 for a sufficient amount of timesuch that the reservoir temperature causes the liquid phase gas 416 tochange phases from a liquid to a gas and infiltrate the fractures andpore volumes 108. For example, the reservoir temperature may range from120 degrees Fahrenheit (F) to greater than 600 degrees F. The gas 416 ina liquid phase may be pumped into the well at a lower temperature (e.g.,−69° F. to 80° F.), and through heat exchange from the highertemperature of the well, can transition from the liquid phase to a gasphase.

In certain implementations, a foam mixture of liquid and gas may bepumped into the well 420, instead of gas 416. The foam may be deliveredthrough a wellhead of the well. In some embodiments, the foam may bedelivered via a storage truck 422 positioned on the ground 424 near thewellhead 426. In other embodiments, the gas 416 may be delivered viapipeline, a storage tank, or other suitable supply sources.

Foam quality is conventionally defined as the volume percent gas withinfoam at a specified pressure and temperature. In certain instances, thequality of the foam may be at least 30. That is, there is at least 30%gas in the foam and the balance is liquid. In certain instances, thequality of the foam may be at least 40. That is, there is at least 40%gas in the foam and the balance is liquid. In certain instances, thequality of the foam may be at least 50. That is, there is at least 50%gas in the foam and the balance is liquid. In certain instances, thequality of the foam may be at least 60. That is, there is at least 60%gas in the foam and the balance is liquid. In certain instances, thequality of the foam may be greater than 70. In certain instances, thequality of the foam may be greater than 80. In certain instances, thequality of the foam may be greater than 90.

A first step in the diversion technique includes injecting a gas 416into a wellbore 418 of a well 420 to pressurize the fractures and/orpore volumes 108 in the lower stress zones 410 of the subterraneanformation 406 and the reservoir. The gas 416 is introduced to infiltratethe formation 406 and the reservoir holding the hydrocarbons. The gas416 can travel through a stimulation network of fractures and/or porevolume (manmade or naturally occurring) extending from the wellbore 418.Upon infiltration, the gas 416 will occupy pore volumes and existingfractures in the formation 406. In some instances, the pore volume andfractures 408 can be preexisting from the natural formation orareas/regions of hydrocarbon depletion. This gas 416 infiltrationcreates a barrier for a carrier liquid 102 that is subsequentlydelivered into the wellbore 418 and diverted to the higher stress zones414. The gas 416 in the stimulation network will build a sufficientpressure, allowing subsequently delivered carrier fluid or liquid 102 tobe diverted into previously untreated areas of the formation.

In all implementations, the gas 416 or foam may infiltrate the fracturesand pore volumes of the formation beyond the wellbore of the well 420 toa distance that is substantial or far-field from the wellbore, outsideof a perforation tunnel, or outside of a formation face in open hole.The gas or foam 416 can infiltrate the fractures and/or pore volumesextending through the length of the well and throughout the reservoir,including far-field areas. This is an advantage of the gas and foam 416that typical chemical and particulate diverter systems do not have. Asan example, in certain implementations, far-field areas of the formationmay be about 10 feet to about 3000 feet from a wellbore or perforationtunnel. In other implementations, far-field areas of the formation maybe about 100 feet to about 5,000 feet from a wellbore or perforationtunnel.

As illustrated in FIG. 5, the carrier liquid 102 may be deliveredthrough the wellhead 526. In some embodiments, the carrier liquid 102may be delivered to the well 520 via a storage truck 526 positioned onthe ground 524 near the well head 526. In certain implementations, thecarrier liquid 102 or an amount of water used in the carrier liquid 102may be supplied by storage tanks, naturally formed features (e.g.,spring), a pipeline, etc.

The carrier liquid 102 may be: slick-water, which is a water-based fluidand proppant combination of a low viscosity; a gel (e.g., borate, HPG,CMHPG, CMC); or a foam (e.g., nitrogen and water with gel, carbondioxide, propane, and combinations thereof), among other carrierliquids. And, as discussed previously, the carrier liquid 102 may becombined with a diverting agent to form a diverting composition that maybe injected into the well.

In the implementations described herein, the gas 416 may besubstantially compressible within the wellbore and the reservoir,whereas the carrier liquid 102 may be substantially incompressible. Thegas 416, as compared with the carrier liquid 102, tends to more easilyfill the fractures and pore volumes because of its compressible nature,has a high relative permeability to the reservoir, and has a lowercoefficient of friction, which allows it to fill the fractures and porevolumes that may not otherwise be penetrated by the carrier liquid 102.The carrier liquid 102, on the other hand, can more readily, as comparedwith the gas 416, fracture the formation of the reservoir, in part,because it is substantially incompressible.

In operation, as seen in the flow chart of FIG. 6, a first step 600 inthe method is injecting the gas or foam 416 into the well 420 andreservoir. As stated previously, the gas or foam 416 is configured topressurize the fractures and pore volumes 108 in the low stress zone410. This step 600 may include initially introducing the gas 416 intothe well 420 by, for example, signaling the storage truck, tanker, orpipeline, among supply sources, 422 containing the gas 416 to beginpumping the gas 416 into the well 420 via the wellhead 426. Alsoincluded in this step 600 may be the halting the flow of gas 416 intothe well 420 by, for example, signaling the storage truck 422 to stopthe flow of gas 416. In other embodiments, the flow of the gas 416 canbe monitored and controlled via a control system that may includepressure, sensors, gauges or switches.

In some embodiments, step 600 can comprise injection of gas using acontinuous flow until the desired volume has been injected. In otherembodiments, step 600 can comprise injecting the gas intermittently, inwhich the flow of the gas can be started, stopped, and started again,and stopped again in succession. In such embodiments, the flow of gascan be started and stopped any number of times until the desired volumehas been injected.

As stated previously, this step 600 may take place over a period ofminutes, hours, days, or weeks depending on the well and the type andavailability of the diverting agent. In certain instances, the step 600of injecting the well 420 with gas or foam 416 may take a period ofhours until a desired pressure is reached within the well 420.Alternatively, in other implementations, gas or foam 416 may be injectedinto the well 420 and it may take a period of weeks for sufficientpressure to be reached in the well 420 to begin injecting the carrierliquid 102. And, over the period of weeks, gas or foam 416 may be addedcontinuously, intermittently, or otherwise.

Next, step 610 includes allowing the gas or foam 416 to remain in thewell 420 and reservoir for a chosen dwell time, if appropriate, giventhe chosen deployment method. For example, with certain deploymentmethods, the gas or foam 416 may be required to remain in the well 420and reservoir for a period of time before the carrier liquid 102 can beinjected into the well 420. For example, if the gas 416 is in a gasphase, there may not be a dwell time. That is, the carrier liquid 102may be injected immediately upon halting of the flow of gas 416 into thewell 420. If the gas 416 is in the liquid phase and the gas will beheated into the gas phase by the heat/energy from the well 420 andreservoir, for example, the gas or foam 416 may need to remain in thewell 420 for a dwell time of about 5 minutes to about 24 hours. Incertain instances, the dwell time may be longer or shorter. In someembodiments, the dwell time can be less than twenty-four hours. In someembodiments, the dwell time can be less than one hour. In someembodiments, the dwell time can be less than thirty minutes. In otherembodiments, the dwell time can be more than twenty-four hours.

Continuing on, the next step 620 in the method is injecting the carrierliquid 102 into the well 420 and reservoir. This step 620 may includeinitially introducing the carrier liquid 102, or a diverting compositionincluding a diverting agent and the carrier liquid 102, into the well420 by, for example, signaling the storage truck or other supply source422 containing the carrier liquid 102 to begin pumping the carrierliquid 102 into the well 420 via the wellhead 426. Also included in thisstep 620 may be halting the flow of carrier liquid 102 into the well 420by, for example, signaling the storage truck, or supply source 422 tostop the flow of carrier liquid 102. Carrier liquid 102 can be injectedat rates of about 2 barrels/minute (bbl/min.) (84 gallons/min.) togreater than 200 bbl/min. (8400 gallons/min).

The next step 630 asks if the previous operations will be repeated. Ifthe well 420 requires additional treatment, for example, to divert theflow of carrier liquid 102 from additional low stress zones 410 thatwere formed from the previous operations to newer high stress zones 414for fracturing. Criteria indicating the need for a re-treatment may, forexample, be if the carrier liquid 102 experiences a high pressure, whichmay indicate the presence of a higher stress zone that may potentiallyfracture. On the other hand, lower pressure in the well 420 may indicatethe carrier fluid 102 is infiltrating lower stress zones. In thissituation, the operations may be repeated or ended depending on theparticulars of the situation. If the operation is to be repeated, gas416 may be re-injected into the well 420 and reservoir for additionaltreatment as described previously with respect to step 600 of themethod. The entire cycle of steps 600, 610, and 620 may be repeated anynumber of times until the end of treatment, at step 640. The methods asdescribed herein can be used to stimulate or treat vertical, deviated,or horizontal wells.

Reference is now made to the flowchart of FIG. 7. As seen in the figure,a first step 700 of the method includes injecting the gas or foam 416into the well 420 and reservoir. The next step 710 asks whether the flowof gas or foam 416 will be stopped before the carrier liquid 102 isinjected into the well 420 and reservoir. In certain implementations,the flow of gas or foam 416 may stop and the carrier liquid 102, or adiverting composition including a diverting agent and the carrier liquid102, may be subsequently injected into the well 420, as was shown inFIG. 6. In other implementations, the flow of gas or foam 416 maycontinue or not be stopped. In these implementations, the carrier liquid102 may be injected into the well 420 at step 720 while the foam or gas416 is also or simultaneously flowing into the well 420. Next, theprevious steps 700, 710, 720 may be repeated, if desired. The treatmentmay be ended at step 740.

It is noted that the carrier liquid 102 may be injected into the well420 by itself or as part of the diverting composition. That is, forexample, a first round of treatment may involve the introduction of thecarrier liquid 102 by itself at step 620, 720 and a subsequent or secondtreatment of the well 420 may involve the introduction of the divertingcomposition (including the carrier liquid 402) at step 620, 720 or viceversa. Alternatively, multiple rounds of well treatment may involve theintroduction of the carrier liquid 102 by itself with some rounds ofwell treatment involving the introduction of the diverting composition(including the carrier liquid 102). As another example, a first round oftreatment may involve the introduction of the diverting composition(including the carrier liquid 102) and a subsequent or second treatmentof the well 420 may involve the introduction of only the carrier liquid102. Other combinations are possible and contemplated herein.

Turning to the flowchart of FIG. 8, at step 800, the gas or foam 416 andthe carrier liquid 102, or a diverting composition including a divertingagent and the carrier liquid 102, may be simultaneously injected intothe well 420 and reservoir without any previous injections of the gas orfoam 416 into the well 420. The gas or foam 416 and the carrier liquid102 may be connected at the wellhead 426 to be delivered downhole. Thegas or foam 416 may mix with the carrier liquid 402 at the wellhead 426or within the wellbore 418. This step 800 may continue until the end oftreatment at step 810.

Reference is now made to FIG. 9, which is a flowchart depicting anothermethod of treating a well. As seen in the figure, at step 900, adiverting composition may be injected into the well and reservoir. Thediverting composition may be the gas or foam 416. Alternatively, thediverting composition may be the diverting composition including adiverting agent mixed with the carrier liquid 102. The next step 910includes asking whether or not a carrier liquid 102 will be injectedinto the well. An affirmative response indicates that carrier liquid 102is injected into the well at step 920. A negative response proceeds toasking whether to inject another diverting composition into the well andreservoir at step 930. A negative response ends treatment at step 940.At step 930, an affirmative response indicates that another divertingcomposition is injected into the well and reservoir at step 900. Asstated previously, the diverting composition may be the gas or foam 416.Alternatively, the diverting composition may be the divertingcomposition including a diverting agent mixed with the carrier liquid102. The steps of this method may continue or end, accordingly. Whilethis method begins at step 900 with injecting a diverting compositioninto the well and reservoir, the method may begin at any step in theprocess. For example, the method may begin at step 920 with injecting acarrier fluid 102 into the well and reservoir.

The steps in this method indicate that an example order of injectionsmay be as follows: a first diverting composition is injected; a seconddiverting composition is injected; and the carrier fluid is injected.Another example order of injections into the well and reservoir may beas follows: a first diverting composition is injected; the carrier fluidis injected; a second diverting composition is injected. In each ofthese examples, the first and second diverting compositions may be thegas or foam 416 or the diverting composition including a diverting agentmixed with the carrier liquid 102. Consequently, and more specifically,the examples above may be as follows: a gas or foam is injected; adiverting composition including the diverting agent mixed with a carrierfluid is injected; the carrier fluid is injected. The second examplemay, more specifically, be as follows: a gas or foam is injected; thecarrier fluid is injected; a diverting composition including thediverting agent mixed with a carrier fluid is injected. These are merelyexamples and other sequences are possible and contemplated herein.

The teachings of this disclosure can be applied in a multi-wellconfiguration, such as one having a target well and multiple injectionwells. As will be appreciated, fluids, whether in the gas or liquidphase, can be injected to surrounding injection wells to influencebehavior of a target well. The behavior can be, for example, fracturingcharacteristics or patterns, valuable fluid production (whether liquidor gas-phase hydrocarbons), and the like. While four equally spacedinjection wells are shown around the target well, any number andsurface/underground well configurations can be employed depending on theapplication.

Referring to FIG. 10, a target well 1000 is surrounded by injectionwells 1004 a,b,c,d. Each injection well is positioned a respectivedistance 1008 a,b,c,d from the target well 1000. The distance is afunction of the type of fluid injected and the permeability and porosityof the underground formations in the underground zones of interest. Eachinjection well 1004 a-d is injected simultaneously or sequentially, inaccordance with the parameters set forth above, with a pressurized fluiddiversion medium, such as a gas, liquid, or mixture thereof (e.g., foam)(which may or may not be in the form of a diverting compositionincluding a diverting agent), at injection pressure PSI at the surfaceand pressure PDHI down hole. The target well 1000 can also be injectedsimultaneously or sequentially with the pressurized fluid at injectionpressure PST at the surface and pressure PDHT down hole. The injectionand down hole pressures are selected according to the teachings of thisdisclosure to induce fracturing in the high stress areas rather than lowstress areas of the target well. The injected fluid in each of theinjection wells will, after a selected period of time, migrate towardsand pressurize the target well. The migration time required forinter-well fluid communication depends on a number of factors includingthe type of fluid injected and the permeabilities and porosities of theunderground formations in the zones of interest. In one configuration, afluid is injected into the target well while in other configurations nofluid is injected into the target well due to fluidization andpressurization of the target well by the fluids injected into the zonesof interest by the injector wells.

The fluid pressures PSI at the surface and PDHI down hole in oneinjection well generally are substantially the same as the respectivefluid pressure in another injection well. Typically, the fluid pressurePSI at a first injection well is within about 25%, more typically withinabout 20%, more typically within about 15%, more typically within about10%, and more typically within about 5% of the fluid pressure PSI at asecond injection well. Likewise, the fluid pressure PDHI at a firstinjection well is within about 25%, more typically within about 20%,more typically within about 15%, more typically within about 10%, andmore typically within about 5% of the fluid pressure PDHI at a secondinjection well. Commonly, the fluid pressure PSI at any injection wellis within about 25%, more typically within about 20%, more typicallywithin about 15%, more typically within about 10%, and more typicallywithin about 5% of the fluid pressure PST at the target well, and thefluid pressure PDHI at any injection well is within about 25%, moretypically within about 20%, more typically within about 15%, moretypically within about 10%, and more typically within about 5% of thefluid pressure PSDHT at the target well.

When the injection and target wells are sufficiently pressurized andafter a suitable injected fluid dwell time in the target well, thecarrier liquid is introduced into the target well 1000 to inducefracturing of high stress areas. The pressurization of the injectionwells can force the fracture to propagate through the high stress areasas the fractures propagate outwardly rather than towards low stressareas

Another multi-well configuration having a target well and multipleinjection wells can be employed using movable isolation device. Themulti-well configuration can fracture a selected formation radiallyoutwardly from a toe of the target well, with the fractures propagatingforwardly and distally from the toe.

As shown in FIGS. 10-11 first and second injector wells are positionedon either side of the target well, which are substantially horizontalinclined. While a horizontal inclination is shown, any inclination ofthe wells, whether vertical or horizontal or a combination thereof ispossible. Movable isolation device 1100 is positioned along a length ofeach of the injection wells 1004 at a selected distance from a toe 1104of each well 1004. Once the movable isolation devices 1100 are inposition (step 1108), a fluid, typically a gas (through a liquid orcombination of gas and liquid can be used), is injected into eachinjection well 1004 (step 1112) as discussed above, so that the injectedfluid moves radially outwardly from the injection well as shown by fluidpenetration profile 1116.

Referring to FIG. 12, the fluid continuously injected into the injectionwells 1004 to continue moving the fluid penetration profile radiallyoutwardly from each injection well as shown by fluid penetration profile1200 (step 1204).

Referring to FIG. 13, the fluid, while still being injectedcontinuously, has moved radially outwardly, whereby the fluid injectedfrom each injection well 1004 has intersected fluidly, forming a fluidpenetration profile 1300 encompassing both inject wells 1004 and thetarget well 1000. As shown by box 1304, the injected fluid has contactedthe pre-existing radial fractures of the target well 1000. Fluid may ormay not be injected into the injection well 1000 during the foregoingsteps. As shown by box 1312, a low pressure zone is created at a toe1316 of the target well 1000. The low pressure zone 1308 may be in ahigh stress area while the other fractures along the length of thetarget well 1000 are in a low stress area. The low pressure zone 1308,however, is defined by the lower penetration of the pressurized andinjected fluid into the low pressure zone 1308 when compared to thepenetration and injected fluid into the fractures along the length ofthe target well 1000. The differential penetration along the length ofthe target well 1000 is caused largely by, and is a function of, theposition of the isolation devices 1100 along the lengths of theinjection wells. Typically, the fluid pressure in the low pressure zone1308 is less than the fluid pressure along the length of the target well1000 where the fluid has penetrated.

Referring to FIG. 14, the progressive fluid penetration profiles 1116,1200, and 1300 of FIGS. 11-13 are depicted along with the low pressurezone 1308 at the toe 1316 of the target well 1000. After a suitablefluid dwell time, a carrier fluid can be injected into the target wellto cause fractures to propagate largely in the low pressure zone 1308outwardly from the toe 1316 as shown by the arrows 1400 rather than inthe weaker or low stress areas along the length of the target well 1000.This is due to the penetration of the injected fluid into thepre-existing fractures, which diverts the carrier fluid away from thepre-existing fracture and towards the toe 1316 of the target well 1000.

The target well 1000 can be deepened followed by repositioning of theisolation devices 1100 farther down the length and/or depth of theinjection wells 1004 and the steps repeated to cause further fracturingfrom the target well 1000.

In another configuration, an isolation device 1100 is positioned fartherdown the length and/or depth of the target well 1000 than along thelength and/or depth of the injection wells 1004. In the example shown,the target well could extend further than depicted (or be deeper) withan isolation device 1100 positioned at the current position of the toe1316, which position would be a distance from the toe of the deeperwell. The isolation devices 1100 in the injection wells 1004 would be inthe same position, causing a spatial offset (along the lengths of thewells) of the isolation devices 1100 in the injection wells from theisolation device in the target well. The steps of FIGS. 11-14 would beperformed to produce fractures propagating forwardly from the positionof the isolation device in the target well. The isolation devices wouldthen be moved deeper into the injection and target wells to produce asimilar spatial offset, and the steps repeated again to producefractures propagating forwardly from the position of the isolationdevice in the target well. These steps can be repeated as frequently aspossible to produce the desired fracture profile along the length of thetarget well.

The technique of FIGS. 11-14 work more effectively when the injectedfluid pressurizes only a portion of the injection wells 1004 and nofluid is introduced into the target well 1000.

Aspects of the presently disclosed technology involve a diversiontechnique for use in vertical, deviated, or horizontal wells undergoinga stimulation process (e.g., initial stimulation or re-stimulation) todivert a carrier liquid from treating previously stimulated areas (i.e.,lower stress zones of the formation) and to force the carrier liquid totreat previously unstimulated areas (i.e., higher stress zones of theformation). The methods disclosed provide cost-effective means forimproving the well production. After a wellbore is drilled andcompleted, stimulation operations are usually performed to enhancehydrocarbon (e.g. gas, oil, etc.) production into the wellbore and toenhance extraction of the hydrocarbons from the subterranean formation.Current diversion techniques use liquid or solid forms, such as chemicalsolutions (e.g., a borate solution) or, particulates (e.g., polymersspheres), which can be costly and potentially ineffective in divertingfluid to the higher stress regions/zones of the reservoir. Additionally,liquid- and solid-form diverters can be problematic as they leaveresidue that can damage the subterranean formation and can lead toinhibited production from the well. In contrast, the methods of thepresent disclosure are cost effective, operationally feasible based oncurrent equipment available to the industry, and can enhance the rate ofextraction of the hydrocarbons. In particular, the use of a gas as thediversion medium allows for greater filling of the reservoir in lowerstress zones such that a carrier liquid can be more efficiently divertedto the higher stress zones of the reservoir. The use of a gas as thediversion medium also has advantages in that no residue remains and thegas can be recovered during flowback. In certain instances, the gas maybe recovered during flowback can be reused, recycled, or marketed.

As seen in FIG. 15, which is a side view of a horizontal drillingoperation 1500 utilizing hydraulic fracturing, a pressurized liquid 1502may cause multiple fractures 1504 within the subterranean formation1506. Fractures 1504 formed by the pressurized liquid 1502 can be ofvarying sizes. Accordingly, larger fractures or pore volumes 1508 maycause a lower stress zone 1510 within the formation such that uponstimulation and re-stimulation of the well the carrier liquid 1502 tendsto concentrate in these lower stress zones 1510. These lower stresszones 1510 can be caused by hydrocarbon depletion, lower pore pressure,and/or higher permeability of the reservoir 1506. Permeability of thereservoir can, in part, depend on the extensiveness of fractures and/orpores, and the interconnectivity of the fractures and/or pores thatcreate pathways for hydrocarbons to flow. As a result of the lowerstress zones, the hydrocarbons are more likely to flow through theselarger fractures or pore volumes 1508, and/or those withinterconnectivity, until depletion. The fractures and/or pore volumes1504 of finer sizes 1512 and/or those lacking interconnectivity tend tobe concentrated in higher stress zones 1514 such that the carrier liquid1502 is less likely to effectively hydraulically fracture those higherstress zones and thus influence the flow of hydrocarbons in theseregions upon stimulation or re-stimulation. This is in part, because thepressure of the carrier liquid 1502 is generally evenly distributedalong the wellbore in the treated area such that the carrier liquid 1502remains concentrated in the lower stress zones 1510 rather than thehigher stress zones 1514. The higher stress zones 1514, in contrast tothe lower stress zones 1510, can be caused by higher pore pressure,ineffective hydraulically fractured regions, lower permeability of thereservoir 1506, or generally less depleted portions of the reservoir1506. As such, the carrier liquid 1502 tends to not affect the higherstress zones 1514, which may contain hydrocarbons, unless additionalsystems and methods are employed.

In subsequent well treatments or in initial well treatments, divertersystems may be used to divert the carrier liquid 1502 from the lowerstress zones 1510, which may be depleted from previous treatments, tothe previously un-accessed, higher stress zones 1514. Diverting thecarrier liquid 1502 into these higher stress zones 1514 may be difficultover large areas of the wellbore and reservoir for a number of reasons.In new wells, the difficulty may be due to differences in stresses fromdifferent lithologies or from different reservoir characteristics alongthe well. Differences in stress can be due to natural in-situ stressconditions or man-made activities such as well stimulation or depletionof fluids. In previously stimulated wells, the difficulty may be due toadequately blocking the fractures and/or pore volume 1508 in the lowerstress zones 1510 such that the carrier liquid 1502 pressurizes thefractures 1512 of the higher stress zones 1514. Diverter systems includethe use of particulates (e.g., polymers) and chemical diverters withinthe carrier liquid 1502, among other methods, to block either thewellbore or the formation near the wellbore so that a portion of thecarrier liquid 1502 may be diverted to the fractures 1512 in the higherstress zones 1514 and also create new fractures in the higher stresszones.

More particularly, and as seen in FIG. 16, which is a side view of ahorizontal drilling operation 1600 utilizing the diversion techniquedescribed herein, a first step in the diversion technique includesinjecting a gas 1616 into a wellbore 1618 of a well 1620 to pressurizethe fractures 1608 in the lower stress zones 1610 of the subterraneanformation 1606 and the reservoir. In certain implementations, the gas1616 may be in a liquid phase, a gas phase, or a foam mixture of gas anda liquid. The gas is introduced to infiltrate the formation 1606 and thereservoir holding the hydrocarbons. The gas can travel through astimulation network of fractures and/or pore volumes (i.e., man-made ornaturally occurring). Upon infiltration, the gas will occupy porevolumes and existing fractures in the formation 1606. In some instances,the pore volume can be preexisting from the natural formation orareas/regions of hydrocarbon depletion. This gas infiltration creates abarrier for a carrier liquid 1502 that is subsequently delivered intothe wellbore and diverted to the higher stress zones 1614. The gas inthe stimulation network can build a sufficient pressure in the networkallowing subsequently delivered carrier fluid or liquid to be divertedinto previously untreated areas of the formation. In some instances,this method will allow for the diversion of a fluid or liquid to aportion of the formation that is a significant distance from thewellbore (i.e. far-field).

The subterranean formation may include one or more of any type of rocks,such as sedimentary rocks like sandstone, limestone, and shale; igneousrocks like granite and andesite; or metamorphic rocks like gneiss,slate, marble, schist, and quartzite. In certain implementations, thesubterranean formation may be a shale formation, a clay formation, asandstone formation, a limestone formation, a carbonate formation, agranite formation, a marble formation, a coal bed, or combinationsthereof.

As seen in FIG. 17, which is a side view of the horizontal drillingoperation 1700 utilizing the diversion techniques described herein, asecond step in the diversion technique includes injecting the carrierliquid 1502 into the wellbore 1718 such that the carrier liquid 1502pressurizes and fractures additional fractures 1712 of the formation1706 that were previously not stimulated. Without injecting the gas 1616into the wellbore, the carrier liquid 1502 would not be diverted tountreated areas and would otherwise infiltrate the fractures 1708 of thelower stress zone 1710. Sufficiently pressurizing the fractures 1708 inthe lower stress zone 1710 causes the subsequently injected carrierliquid 1502 to bypass the gas-filled, pressurized fractures 1708 in thelower stress zones 1710 and can be directed to infiltrating thefractures 1712 of the high stress zone 1714 or create new fractures.

The gas 1616 may be delivered through a wellhead 1726 of the well 1720.In some embodiments, the gas 1616 may be delivered via a storage truck1622 positioned on the ground 1724 near the wellhead 1726. In otherembodiments, the gas 1616 may be delivered via pipeline, a storage tank,other gas producing wells, or other suitable supply sources.

Factors effecting the volume of gas 1616 to be introduced in the well1720 include the size of the depleted regions of the reservoir(including pore volume and fractures), leak off rate of the gas 1616,and the extent of existing fracture and reservoir conditions (e.g.reservoir pressure—if the pressure is high it will compress the gas orfoam requiring more volume to occupy the fractures/pore volumes).

For instance, in some embodiments, the volume of the gas can range fromabout 1000 standard cubic feet (scf) to about 100,000,000 scf orgreater. In various embodiments, the gas can be injected at rates withina range of about 30 scf/min to about 500,000 scf/min. In someembodiments, the gas can be injected at a rate of about 10,000 to about20,000 scf/min.

In certain instances, the gas 1616 may be injected into the well over anextended period of time. For example, the gas 1616 may be injected overa period of time that can be minutes, hours, days, or months, dependingon a number of factors. In some embodiments, the gas 1616 may beinjected over a period of time of at least 2 hrs. In other embodiments,the gas 1616 may be injected over a period of time of at least a day.For example, in certain instances, the gas 1616 may be injected into thewell from a neighboring natural gas well, for example. A worker maycheck the pressure at a subsequent time (e.g., days later) and determinethat, in order to meet a desired pressure within the wellbore,additional gas 1616 may need to be injected into the wellbore andcontinue the injection of the gas. A subsequent check of the pressure(e.g., days later), may indicate that the pressure is sufficient for theintroduction of the carrier liquid 1502. Thus, in this example, it ispossible for weeks to go by with intermittent addition of gas 1616 intothe well before a sufficient pressure is reached to begin introductionof the carrier liquid 1502.

The gas 1616 may include any number of gasses and may include nitrogen,hydrogen, methane, ethane, propane, butane, carbon dioxide, any inertgas, or any combinations thereof. The gas 1616 may be deployed into thewell 1720 in a number of ways and in various phases. In certainimplementations, the gas 1616 may be in a gas phase and pumped directlyinto the wellbore 1718 from the wellhead 1726. In other implementations,the gas 1616 may be in a liquid phase above ground 1724, and the gas1616 is heated sufficiently at the surface for the gas 1616 to enter thegas phase as it is being introduced into the wellbore 1718, therebybeing in the gas phase when it infiltrates the pore volumes and/orfractures. In yet other implementations, the gas may be in a liquidphase when it is introduced to the wellbore. The gas in the liquid phasemay be pumped into the well and allowed to remain in the well 1720 for asufficient amount of time such that the reservoir temperature causes theliquid phase gas 1616 to change phases from a liquid to a gas andinfiltrate the fractures and pore volumes 1508. For example, thereservoir temperature may range from 1620 degrees Fahrenheit (F) togreater than 600 degrees F. The gas 1616 in a liquid phase may be pumpedinto the well at a lower temperature (e.g., −69 F to 80° F.), andthrough heat exchange from the higher temperature of the well, cantransition from the liquid phase to a gas phase.

In certain implementations, a foam mixture of liquid and gas may bepumped into the well 1720, instead of gas 1616. The foam may bedelivered through a wellhead of the well. In some embodiments, the foammay be delivered via a storage truck 1622 positioned on the ground 1724near the wellhead 1726. In other embodiments, the gas 1616 may bedelivered via pipeline, a storage tank, or other suitable supplysources.

Foam quality is conventionally defined as the volume percent gas withinfoam at a specified pressure and temperature. In certain instances, thequality of the foam may be at least 30. That is, there is at least 30%gas in the foam and the balance is liquid. In certain instances, thequality of the foam may be at least 40. That is, there is at least 40%gas in the foam and the balance is liquid. In certain instances, thequality of the foam may be at least 50. That is, there is at least 50%gas in the foam and the balance is liquid. In certain instances, thequality of the foam may be at least 60. That is, there is at least 60%gas in the foam and the balance is liquid. In certain instances, thequality of the foam may be greater than 70. In certain instances, thequality of the foam may be greater than 80. In certain instances, thequality of the foam may be greater than 90.

A first step in the diversion technique includes injecting a gas 1616into a wellbore 1718 of a well 1720 to pressurize the fractures and/orpore volumes 1508 in the lower stress zones 1710 of the subterraneanformation 1706 and the reservoir. The gas 1616 is introduced toinfiltrate the formation 1706 and the reservoir holding thehydrocarbons. The gas 1616 can travel through a stimulation network offractures and/or pore volume (manmade or naturally occurring) extendingfrom the wellbore 1718. Upon infiltration, the gas 1616 will occupy porevolumes and existing fractures in the formation 1706. In some instances,the pore volume and fractures 1708 can be preexisting from the naturalformation or areas/regions of hydrocarbon depletion. This gas 1616infiltration creates a barrier for a carrier liquid 1502 that issubsequently delivered into the wellbore 1718 and diverted to the higherstress zones 1714. The gas 1616 in the stimulation network will build asufficient pressure, allowing subsequently delivered carrier fluid orliquid 1502 to be diverted into previously untreated areas of theformation.

In all implementations, the gas 1616 or foam may infiltrate thefractures and pore volumes of the formation beyond the wellbore of thewell 1720 to a distance that is substantial or far-field from thewellbore, outside of a perforation tunnel, or outside of a formationface in open hole. The gas or foam 1616 can infiltrate the fracturesand/or pore volumes extending through the length of the well andthroughout the reservoir, including far-field areas. This is anadvantage of the gas and foam 1616 that typical chemical and particulatediverter systems do not have. As an example, in certain implementations,far-field areas of the formation may be about 10 feet to about 3000 feetfrom a wellbore or perforation tunnel. In other implementations,far-field areas of the formation may be about 100 feet to about 5,000feet from a wellbore or perforation tunnel.

As illustrated in FIG. 17, the carrier liquid 1502 may be deliveredthrough the wellhead 1726. In some embodiments, the carrier liquid 1502may be delivered to the well 1720 via a storage truck 1726 positioned onthe ground 1724 near the well head 1726. In certain implementations thecarrier liquid 1502 or an amount of water used in the carrier liquid1502 may be supplied by storage tanks, naturally formed features (e.g.,spring), a pipeline, etc.

The carrier liquid 1502 may be: slick-water, which is a water-basedfluid and proppant combination of a low viscosity; a gel (e.g., borate,HPG, CMHPG, CMG); or a foam (e.g., nitrogen and water with gel, carbondioxide, propane, and combinations thereof), among other carrierliquids.

In the implementations described herein, the gas 1616 may besubstantially compressible within the wellbore and the reservoir,whereas the carrier liquid 1502 may be substantially incompressible. Thegas 1616, as compared with the carrier liquid 1502, tends to more easilyfill the fractures and pore volumes because of its compressible nature,has a high relative permeability to the reservoir, and has a lowercoefficient of friction, which allows it to fill the fractures and porevolumes that may not otherwise be penetrated by the carrier liquid 1502.The carrier liquid 1502, on the other hand, can more readily, ascompared with the gas 1616, fracture the formation of the reservoir, inpart, because it is substantially incompressible.

In operation, as seen in the flow chart of FIG. 18, a first step 1800 inthe method is injecting the gas or foam 1616 into the well 1620 andreservoir. As stated previously, the gas or foam 1616 is configured topressurize the fractures and pore volumes 1508 in the low stress zone1610. This step 1800 may include initially introducing the gas 1616 intothe well 1620 by, for example, signaling the storage truck, tanker, orpipeline, among supply sources, 1622 containing the gas 1616 to beginpumping the gas 1616 into the well 1620 via the wellhead 1626. Alsoincluded in this step 1800 may be the halting the flow of gas 1616 intothe well 1620 by, for example, signaling the storage truck 1622 to stopthe flow of gas 1616. In other embodiments, the flow of the gas 1616 canbe monitored and controlled via a control system that may includepressure sensors, gauges or switches.

In some embodiments, step 1800 can comprise injection of gas using acontinuous flow until the desired volume has been injected. In otherembodiments, step 1800 can comprise injecting the gas intermittently, inwhich the flow of the gas can be started, stopped, and started again,and stopped again in succession. In such embodiments, the flow of gascan be started and stopped any number of times until the desired volumehas been injected.

As stated previously, this step 1800 may take place over a period ofminutes, hours, days or weeks depending on the well and the type andavailability of the diverting agent. In certain instances, the step 1800of injecting the well 1620 with gas or foam 1616 may take a period ofhours until a desired pressure is reached within the well 1620.Alternatively, in other implementations, gas or foam 1616 may beinjected into the well 1620 and it may take a period of weeks forsufficient pressure to be reached in the well 1620 to begin injectingthe carrier liquid 1502. And, over the period of weeks, gas or foam 1616may be added continuously, intermittently, or otherwise.

Next, step 1810 includes allowing the gas or foam 1616 to remain in thewell 1620 and reservoir for a chosen dwell time, if appropriate, giventhe chosen deployment method. For example, with certain deploymentmethods, the gas or foam 1616 may be required to remain in the well 1620and reservoir for a period of time before the carrier liquid 1502 can beinjected into the well 1620. For example, if the gas 1616 is in a gasphase, there may not be a dwell time. That is, the carrier liquid 1502may be injected immediately upon halting of the flow of gas 1616 intothe well 1620. If the gas 1616 is in the liquid phase and the gas willbe heated into the gas phase by the heat/energy from the well 1620 andreservoir, for example, the gas or foam 1616 may need to remain in thewell 1620 for a dwell time of about 5 minutes to about 24 hours. Incertain instances, the dwell time may be longer or shorter. In someembodiments, the dwell time can be less than twenty-four hours. In someembodiments, the dwell time can be less than one hour. In someembodiments, the dwell time can be less than thirty minutes. In otherembodiments, the dwell time can be more than twenty-four hours.Continuing on, the next step 1820 in the method is injecting the carrierliquid 1502 into the well 1620 and reservoir. This step 1820 may includeinitially introducing the carrier liquid 1502 into the well 1620 by, forexample, signaling the storage truck or other supply source 1726containing the carrier liquid 1502 to begin pumping the carrier liquid1502 into the well 1620 via the wellhead 1626. Also included in thisstep 1820 may be halting the flow of carrier liquid 1502 into the well1620 by, for example, signaling the storage truck, or supply source 1622to stop the flow of carrier liquid 1502. Carrier liquid 1502 can beinjected at rates of about 2 barrels/minute (bbl/min.) (84 gallons/min.)to greater than 200 bbl/min. (8400 gallons/min).

The next step 1830 asks if the previous operations will be repeated. Ifthe well 1620 requires additional treatment, for example, to divert theflow of carrier liquid 1502 from additional low stress zones 1610 thatwere formed from the previous operations to newer high stress zones 1614for fracturing. Criteria indicating the need for a re-treatment may, forexample, be if the carrier liquid 1502 experiences a high pressure,which may indicate the presence of a higher stress zone that maypotentially fracture. On the other hand, lower pressure in the well 1620may indicate the carrier fluid 1502 is infiltrating lower stress zones.In this situation, the operations may be repeated or ended depending onthe particulars of the situation. If the operation is to be repeated,gas 1616 may be re-injected into the well 1620 and reservoir foradditional treatment as described previously with respect to step 1800of the method. The entire cycle of steps 1800, 1810, and 1820 may berepeated any number of times until the end of treatment, at step 1840.The methods as described herein can be used to stimulate or treatvertical, deviated, or horizontal wells.

Reference is now made to the flowchart of FIG. 19. As seen in thefigure, a first step 1900 of the method includes injecting the gas orfoam 1616 into the well 1620 and reservoir. The next step 1910 askswhether the flow of gas or foam 1616 will be stopped before the carrierliquid 1502 is injected into the well 1620 and reservoir. In certainimplementations, the flow of gas or foam 1616 may stop and the carrierliquid 1502 may be subsequently injected into the well 1620, as wasshown in FIG. 18. In other implementations, the flow of gas or foam 1616may continue or not be stopped. In these implementations, the carrierliquid 1502 may be injected into the well 1620 at step 1920 while thefoam or gas 1616 is also or simultaneously flowing into the well 1620.Next, the previous steps 1900, 1910, 1920 may be repeated, if desired.The treatment may be ended at step 1940.

Turning to the flowchart of FIG. 20, at step 2000, the gas or foam 1616and the carrier liquid 1502 may be simultaneously injected into the well1620 and reservoir without any previous injections of the gas or foam1616 into the well 1620. The gas or foam 1616 and the carrier liquid1502 may be connected at the wellhead 1626 to be delivered downhole. Thegas or foam 1616 may mix with the carrier liquid 1502 at the wellhead1626 or within the wellbore 1618. This step 2000 may continue until theend of treatment at step 2010.

Various modifications and additions can be made to the exemplaryembodiments discussed without departing from the spirit and scope of thepresently disclosed technology. For example, while the embodimentsdescribed above refer to particular features, the scope of thisdisclosure also includes embodiments having different combinations offeatures and embodiments that do not include all of the describedfeatures. Accordingly, the scope of the presently disclosed technologyis intended to embrace all such alternatives, modifications, andvariations together with all equivalents thereof.

A number of variations and modifications of the disclosure can be used.It would be possible to provide for some features of the disclosurewithout providing others.

The present disclosure, in various aspects, embodiments, andconfigurations, includes components, methods, processes, systems and/orapparatus substantially as depicted and described herein, includingvarious aspects, embodiments, configurations, sub-combinations, andsubsets thereof. Those of skill in the art will understand how to makeand use the various aspects, aspects, embodiments, and configurations,after understanding the present disclosure. The present disclosure, invarious aspects, embodiments, and configurations, includes providingdevices and processes in the absence of items not depicted and/ordescribed herein or in various aspects, embodiments, and configurationshereof, including in the absence of such items as may have been used inprevious devices or processes, e.g., for improving performance,achieving ease and\or reducing cost of implementation.

The foregoing discussion of the disclosure has been presented forpurposes of illustration and description. The foregoing is not intendedto limit the disclosure to the form or forms disclosed herein. In theforegoing Detailed Description for example, various features of thedisclosure are grouped together in one or more, aspects, embodiments,and configurations for the purpose of streamlining the disclosure. Thefeatures of the aspects, embodiments, and configurations of thedisclosure may be combined in alternate aspects, embodiments, andconfigurations other than those discussed above. This method ofdisclosure is not to be interpreted as reflecting an intention that theclaimed disclosure requires more features than are expressly recited ineach claim. Rather, as the following claims reflect, inventive aspectslie in less than all features of a single foregoing disclosed aspects,embodiments, and configurations. Thus, the following claims are herebyincorporated into this Detailed Description, with each claim standing onits own as a separate preferred embodiment of the disclosure.

Moreover, though the description of the disclosure has includeddescription of one or more aspects, embodiments, or configurations andcertain variations and modifications, other variations, combinations,and modifications are within the scope of the disclosure, e.g., as maybe within the skill and knowledge of those in the art, afterunderstanding the present disclosure. It is intended to obtain rightswhich include alternative aspects, embodiments, and configurations tothe extent permitted, including alternate, interchangeable and/orequivalent structures, functions, ranges or steps to those claimed,whether or not such alternate, interchangeable and/or equivalentstructures, functions, ranges or steps are disclosed herein, and withoutintending to publicly dedicate any patentable subject matter.

What is claimed is:
 1. A method of influencing one or more of fracturingcharacteristics or patterns and hydrocarbon fluid production in a targetwell, comprising: (a) providing a pressurized fluid diversion mediumcomprising a material, wherein the material comprises a diverting agent;(b) introducing the pressurized fluid diversion medium into at least twoinjection wells spatially proximate to a target well; (c) allowing thematerial to migrate into pre-existing fractures in the at least twoinjection wells; (d) after a suitable injected fluid dwell time of thepressurized fluid diversion medium, introducing a carrier liquid intothe target well to stimulate and induce hydraulic fracturing in thetarget well; and (e) producing, after the stimulation, hydrocarbonfluid, wherein the target well and the injection wells are not allcollinear, wherein the pressurized fluid diversion medium is maintainedat an injection pressure below a fracture gradient of the subterraneanformation during the duration of step (b) to inhibit hydraulicfracturing of the pre-existing fractures in the at least two injectionwells, and wherein the carrier liquid is injected into the target wellat a sufficient pressure above the fracture gradient to fracture thesubterranean formation.
 2. The method of claim 1, wherein thepressurized fluid diversion medium comprises one of a gas, a liquid, ora mixture thereof, wherein the diverting agent is a chemical,biological, or mechanical diverting agent and wherein the pressurizedfluid diversion medium infiltrates and occupies pore volumes of thesubterranean formation in an area of the subterranean formation to adistance of about 10 to about 3000 feet from the wellbore.
 3. The methodof claim 1, wherein pressurization of the pre-existing fracturesadjacent to the injection well by the pressurized fluid diversion mediuminhibits fracturing of the pressurized pre-existing fractures adjacentto the well by the carrier liquid in the target well, wherein the chosendwell time is more than twenty-four hours and wherein the pressurizedfluid diversion medium infiltrates and occupies pore volumes of thesubterranean formation in an area of the subterranean formation to adistance of about 100 to about 5000 feet from the wellbore.
 4. Themethod of claim 1, wherein the diverting agent is one or more of sand,ceramic proppant, resin coated proppant, salt, degradable fiber, starch,gel, guar, ceramic bead, bauxite, glass microsphere, synthetic organicbead, sintered material, polymeric material, polytetrafluoroethyleneparticulates, seed shell pieces, and cured resinous particulates.
 5. Themethod of claim 1, wherein the diverting agent is selected from thegroup consisting essentially of homopolymers, random block polymers,graft polymers, star-polymers, hyper-branched polymers, a degradablepolymer, dehydrated compound, a polysaccharide, chitin, chitosan,protein, aliphatic polyester, poly(lactide), poly(glycolide),poly(ε-caprolactone), poly(hydroxybutyrate), poly(anhydrides), aliphaticpolycarbonate, poly(ortho ester), poly(amino acid), poly(ethyleneoxide), polyphosphazenes, and polyanhydride.
 6. The method of claim 1,wherein the pressurized fluid diversion medium further comprises a gas,wherein the gas comprises one or more of: nitrogen, hydrogen, methane,ethane, propane, butane, carbon dioxide, or an inert gas and wherein thegas migrates through a stimulation network of manmade and naturallyoccurring fractures and/or pore volumes to create a barrier.
 7. Themethod of claim 1, wherein the chosen dwell time ranges from about 5minutes to about twenty-four hours and wherein the diverting agent isone of: (i) a mechanical diverting agent; (ii) a degradable fiber; (iii)a chemical diverting agent; or (iv) a polyanhydride.
 8. The method ofclaim 1, wherein one of the following is true: (a) the pressurized fluiddiversion medium is injected into the target well simultaneously orsequentially with injection of the pressurized fluid diversion medium inthe at least two injection wells; and (b) the pressurized fluiddiversion medium is not injected into the target well simultaneously orsequentially with injection of the pressurized fluid diversion medium inthe at least two injection wells.
 9. The method of claim 1, wherein thepressurized fluid diversion medium is free of liquid.
 10. The method ofclaim 1, wherein the pressurized fluid diversion medium comprises nomore than about 50 volume % liquid.
 11. The method of claim 1, whereinthe pressurized fluid diversion medium is free of solid particulates.12. The method of claim 1, wherein the pressurized fluid diversionmedium comprises no more than about 5 volume % solid particulates.
 13. Amethod of influencing one or more of fracturing characteristics orpatterns and hydrocarbon fluid production in a target well, comprising:providing a fluid diversion medium in the form of a mixture containing adiverting agent comprising one of a chemical, biological, or mechanicaldiverting agent; pressurizing the fluid diversion medium; introducingthe pressurized fluid diversion medium into an injection well spatiallyproximate a target well; allowing the pressurized fluid diversion mediumto migrate into pre-existing fractures to form pressurized pre-existingfractures in a subterranean formation adjacent to the injection well;and maintaining, for a suitable injected fluid dwell time, thepressurized fluid diversion medium in the pressurized pre-existingfractures while a carrier liquid is introduced into the target well toinduce fracturing in the target well, wherein the pressurized fluiddiversion medium is maintained at an infection pressure below a fracturegradient of the subterranean formation during the duration of theintroducing step, and wherein the carrier liquid is injected into thetarget well at a sufficient pressure above the fracture gradient tofracture the subterranean formation.
 14. The method of claim 13, whereinpressurization of the pre-existing fractures adjacent to the injectionwell by the pressurized fluid diversion medium inhibits fracturing ofthe pressurized pre-existing fractures adjacent to the well by thecarrier liquid in the target well, wherein a portion of the pressurizedfluid diversion medium occupies the pressurized pre-existing fracturesin the injection well at a sufficient pressure to cause the carrierliquid to be diverted to fracture additional features of thesubterranean formation to form additional fractures or pore volumes andwherein the pressurized fluid diversion medium diverts the carrierliquid from fracturing a previously stimulated area comprising thepre-existing fractures and forces the carrier liquid to fracture apreviously unstimulated area, wherein the carrier liquid comprises aproppant, wherein the pressurized fluid diversion medium comprises oneof a gas, a liquid, or a mixture thereof, wherein the pressurized fluiddiversion medium infiltrates and occupies pore volumes of thesubterranean formation in an area of the subterranean formation to adistance of about 10 to about 3000 feet from the wellbore.
 15. Themethod of claim 13, wherein a portion of the pressurized fluid diversionmedium occupies the pressurized pre-existing fractures in the injectionwell at a sufficient pressure to cause the carrier liquid to be divertedto fracture additional features of the subterranean formation to formadditional fractures or pore volumes and wherein the pressurized fluiddiversion medium diverts the carrier liquid from fracturing a previouslystimulated area comprising the pre-existing fractures and forces thecarrier liquid to fracture a previously unstimulated area, wherein thediverting agent is one or more of sand, ceramic proppant, resin coatedproppant, salt, degradable fiber, starch, gel, guar, ceramic bead,bauxite, glass microsphere, synthetic organic bead, sintered material,polymeric material, polytetrafluoroethylene particulates, seed shellpieces, and cured resinous particulates.
 16. The method of claim 13,wherein the diverting agent is selected from the group consistingessentially of a homopolymer, a random, block, graft, and star- orhyper-branched polymer, a degradable polymer, dehydrated compound, apolysaccharide, chitin, chitosan, protein, aliphatic polyester,poly(lactide), poly(glycolide), poly(ε-caprolactone),poly(hydroxybutyrate), poly(anhydrides), aliphatic polycarbonate,poly(ortho ester), poly(amino acid), poly(ethylene oxide),polyphosphazenes, polyanhydride, and mixtures thereof.
 17. The method ofclaim 13, wherein a portion of the pressurized fluid diversion mediumoccupies the pressurized pre-existing fractures in the injection well ata sufficient pressure to cause the carrier liquid to be diverted tofracture additional features of the subterranean formation to formadditional fractures or pore volumes and wherein the pressurized fluiddiversion medium diverts the carrier liquid from fracturing a previouslystimulated area comprising the pre-existing fractures and forces thecarrier liquid to fracture a previously unstimulated area, wherein thepressurized fluid diversion medium is substantially compressible and thecarrier liquid is substantially incompressible, wherein the pressurizedfluid diversion medium comprises no more than about 1% by volume solidparticulates, wherein the pressurized fluid diversion medium furthercomprises a gas, wherein the pressurized fluid diversion mediumcomprises at least about 50% gas by volume, wherein the injectionpressure of the injected gas composition in the introducing step is nomore than about 85% of a fracture gradient of the subterraneanformation, wherein the gas comprises one or more of: nitrogen, hydrogen,methane, ethane, propane, butane, carbon dioxide, or an inert gas,wherein a gas injection rate into the wellbore in the introducing stepranges from about 10,000 to about 20,000 scf/min, wherein thepressurized pre-existing fractures are lower stress zones of thesubterranean formation, wherein the additional features are higherstress zones of the subterranean formation, and wherein the gas travelsthrough a stimulation network of manmade and naturally occurringfractures and/or pore volumes to create a barrier.
 18. The method ofclaim 13, wherein the chosen dwell time ranges from about 5 minutes toabout twenty-four hours and wherein the diverting agent is a mechanicaldiverting agent and wherein the mechanical diverting agent includes adegradable fiber.
 19. The method of claim 13, wherein a portion of thepressurized fluid diversion medium occupies the pressurized pre-existingfractures in the injection well at a sufficient pressure to cause thecarrier liquid to be diverted to fracture additional features of thesubterranean formation to form additional fractures or pore volumes andwherein the pressurized fluid diversion medium diverts the carrierliquid from fracturing a previously stimulated area comprising thepre-existing fractures and forces the carrier liquid to fracture apreviously unstimulated area and wherein the chosen dwell time rangesfrom about 5 minutes to about twenty-four hours and wherein thediverting agent is a chemical diverting agent and wherein the chemicaldiverting agent is a polyanhydride.
 20. The method of claim 13, whereina portion of the pressurized fluid diversion medium occupies thepressurized pre-existing fractures in the injection well at a sufficientpressure to cause the carrier liquid to be diverted to fractureadditional features of the subterranean formation to form additionalfractures or pore volumes and wherein the pressurized fluid diversionmedium diverts the carrier liquid from fracturing a previouslystimulated area comprising the pre-existing fractures and forces thecarrier liquid to fracture a previously unstimulated area and whereinone of the following is true: (a) the pressurized fluid diversion mediumis injected into the target well simultaneously or sequentially withinjection of the pressurized fluid diversion medium in the injectionwell; and (b) the pressurized fluid diversion medium is not injectedinto the target well simultaneously or sequentially with injection ofthe pressurized fluid diversion medium in the injection well.
 21. Themethod of claim 13, wherein the fluid diversion medium is free ofliquid.
 22. The method of claim 13, wherein the fluid diversion mediumcomprises no more than about 50 volume % liquid.
 23. The method of claim13, wherein the fluid diversion medium is free of solid particulates.24. The method of claim 13, wherein the fluid diversion medium comprisesno more than about 5 volume % solid particulates.
 25. A method ofinfluencing one or more of fracturing characteristics or patterns andhydrocarbon fluid production in a target well, comprising: (a) providinga pressurized fluid diversion medium comprising a material, wherein thematerial comprises a diverting agent, wherein the diverting agent is achemical diverting agent; (b) introducing the pressurized fluiddiversion medium into at least one injection well spatially proximate toa target well; (c) allowing the material to migrate into pre-existingfractures to form pressurized pre-existing fractures in a subterraneanformation adjacent to at least one injection well; and (d) after asuitable injected fluid dwell time of the pressurized fluid diversionmedium in the pressurized pre-existing fractures, introducing a carrierliquid into the target well to induce fracturing in the target well,wherein the pressurized fluid diversion medium is maintained at aninjection pressure below a fracture gradient of the subterraneanformation during the duration of step (b) to inhibit hydraulicfracturing of the pressurized pre-existing fractures adjacent to the atleast one injection well by the carrier liquid in the target well, andwherein the carrier liquid is injected into the target well at asufficient pressure above the fracture gradient to fracture thesubterranean formation.
 26. The method of claim 25, wherein a portion ofthe pressurized fluid diversion medium occupies the pressurizedpre-existing fractures in the injection well at a sufficient pressure tocause the carrier liquid to be diverted to fracture additional featuresof the subterranean formation to form additional fractures or porevolumes and wherein the pressurized fluid diversion medium diverts thecarrier liquid from fracturing a previously stimulated area comprisingthe pre-existing fractures and forces the carrier liquid to fracture apreviously unstimulated area, wherein the pressurized fluid diversionmedium comprises one of a gas, a liquid, or a mixture thereof, whereinthe diverting agent is a chemical, biological, or mechanical divertingagent, wherein the carrier liquid comprises a proppant, and wherein thepressurized fluid diversion medium infiltrates and occupies pore volumesof the subterranean formation in an area of the subterranean formationto a distance of about 100 to about 5000 feet from the wellbore.
 27. Themethod of claim 25, wherein the chosen dwell time is more thantwenty-four hours and wherein the pressurized fluid diversion mediuminfiltrates and occupies pore volumes of the subterranean formation inan area of the subterranean formation to a distance of about 10 to about3000 feet from the wellbore.
 28. The method of claim 25, wherein aportion of the pressurized fluid diversion medium occupies thepressurized pre-existing fractures in the injection well at a sufficientpressure to cause the carrier liquid to be diverted to fractureadditional features of the subterranean formation to form additionalfractures or pore volumes and wherein the pressurized fluid diversionmedium diverts the carrier liquid from fracturing a previouslystimulated area comprising the pre-existing fractures and forces thecarrier liquid to fracture a previously unstimulated area, wherein thediverting agent is one or more of sand, ceramic proppant, resin coatedproppant, salt, degradable fiber, starch, gel, guar, ceramic bead,bauxite, glass microsphere, synthetic organic bead, sintered material,polymeric material, polytetrafluoroethylene particulates, seed shellpieces, and cured resinous particulates.
 29. The method of claim 25,wherein a portion of the pressurized fluid diversion medium occupies thepressurized pre-existing fractures in the injection well at a sufficientpressure to cause the carrier liquid to be diverted to fractureadditional features of the subterranean formation to form additionalfractures or pore volumes and wherein the pressurized fluid diversionmedium diverts the carrier liquid from fracturing a previouslystimulated area comprising the pre-existing fractures and forces thecarrier liquid to fracture a previously unstimulated area, wherein thediverting agent is degradable and the degradable diverting agent isselected from the group consisting essentially of a degradable polymer,dehydrated compound, and mixtures thereof and wherein the divertingagent is selected from the group consisting essentially of ahomopolymer, a random, block, graft, and star- or hyper-branchedpolymer, and mixtures thereof.
 30. The method of claim 25, wherein aportion of the pressurized fluid diversion medium occupies thepressurized pre-existing fractures in the injection well at a sufficientpressure to cause the carrier liquid to be diverted to fractureadditional features of the subterranean formation to form additionalfractures or pore volumes and wherein the pressurized fluid diversionmedium diverts the carrier liquid from fracturing a previouslystimulated area comprising the pre-existing fractures and forces thecarrier liquid to fracture a previously unstimulated area, wherein thediverting agent is degradable and the degradable diverting agent isselected from the group consisting essentially of a degradable polymer,dehydrated compound, and mixtures thereof and wherein the divertingagent is selected from the group consisting essentially of apolysaccharide, chitin, chitosan, protein, aliphatic polyester,poly(lactide), poly(glycolide), poly(ε-caprolactone),poly(hydroxybutyrate), poly(anhydrides), aliphatic polycarbonate,poly(ortho ester), poly(amino acid), poly(ethylene oxide),polyphosphazenes, and polyanhydride.
 31. The method of claim 25, whereinthe pressurized fluid diversion medium is substantially compressible andthe carrier liquid is substantially incompressible, wherein thepressurized fluid diversion medium comprises no more than about 1% byvolume solid particulates, wherein the pressurized fluid diversionmedium further comprises a gas, wherein the pressurized fluid diversionmedium comprises at least about 50% gas by volume, wherein the injectionpressure of the injected gas composition in the introducing step is nomore than about 85% of a fracture gradient of the subterraneanformation, wherein the gas comprises one or more of: nitrogen, hydrogen,methane, ethane, propane, butane, carbon dioxide, or an inert gas,wherein a gas injection rate into the wellbore in the introducing stepranges from about 10,000 to about 20,000 scf/min, wherein thepressurized pre-existing fractures are lower stress zones of thesubterranean formation, wherein the additional features are higherstress zones of the subterranean formation, and wherein the gas travelsthrough a stimulation network of manmade and naturally occurringfractures and/or pore volumes to create a barrier.
 32. The method ofclaim 25, wherein the chosen dwell time ranges from about 5 minutes toabout twenty-four hours and wherein the diverting agent is a mechanicaldiverting agent and wherein the mechanical diverting agent includes adegradable fiber.
 33. The method of claim 25, wherein the chosen dwelltime ranges from about 5 minutes to about twenty-four hours and whereinthe diverting agent is a chemical diverting agent and wherein thechemical diverting agent is a polyanhydride.
 34. The method of claim 25,wherein one of the following is true: (a) the pressurized fluiddiversion medium is injected into the target well simultaneously orsequentially with injection of the pressurized fluid diversion medium inthe at least one injection well; and (b) the pressurized fluid diversionmedium is not injected into the target well simultaneously orsequentially with injection of the pressurized fluid diversion medium inthe at least one injection well.
 35. The method of claim 25, wherein thepressurized fluid diversion medium is free of liquid.
 36. The method ofclaim 25, wherein the pressurized fluid diversion medium comprises nomore than about 50 volume % liquid.
 37. The method of claim 25, whereinthe pressurized fluid diversion medium is free of solid particulates.38. The method of claim 25, wherein the pressurized fluid diversionmedium comprises no more than about 5 volume % solid particulates.